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 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 – TABLE OF CONTENTS
PAGE
DISCLAIMER...... i
EXECUTIVE SUMMARY: CONCLUSIONS AND KEY MESSAGES...... vii
1.0 INTRODUCTION ...... 1 1.1 General...... 1 1.2 Objectives...... 1 1.3 Approach ...... 2 1.4 Other Chemical Centers...... 3 1.5 BASF et al Port Arthur, TX Expansion Project Examples...... 6 1.6 Financial Analyses Bases...... 9 1.7 Gas Oil Note ...... 11 1.7.1 Light “Gas Oil”...... 11
2.0 FEEDSTOCKS ...... 12 2.1 Introduction...... 12 2.2 Reference Prices ...... 12 2.3 Bitumen Supply ...... 12 2.4 Vacuum / Heavy Gas Oils ...... 14 2.5 Natural Gas Liquids...... 14 2.6 Synthetic Gas Liquids...... 15 2.7 Refinery Olefinic C3 C4’s...... 17 2.8 Ethylene Plant C3 Plus Streams ...... 17 2.9 Joffre Ethylene Plant Hydrogen...... 18 2.10 CO2 from Others ...... 18 2.11 Refinery Naphthas...... 18 2.12 Feed Delivery Systems...... 18
3.0 PRODUCTS...... 19 3.1 Introduction...... 19 3.2 Petrochemical Products...... 19 3.2.1 Preamble ...... 19 3.2.2 Ethylene ...... 19 3.2.3 Propylene ...... 20 3.2.4 Benzene ...... 21 3.2.5 P-xylene ...... 21 3.3 Refined Products...... 21 3.3.1 General – British Columbia ...... 21 3.3.2 Gasoline ...... 22 3.3.3 C4 Alkylate...... 23 3.3.4 Jet Fuel...... 23 3.3.5 Diesels...... 23 3.3.6 Heavy Aromatics ...... 24 3.3.7 Naphthas ...... 24 3.3.8 Synthetic Crude Oils...... 24 3.4 Hydrogen ...... 24 3.5 CO2 ...... 25 3.6 Specialties ...... 25 3.6.1 Synopsis...... 25 3.6.2 Options ...... 26 3.7 Major Prospects...... 26 3.8 Infrastructure ...... 30 3.8.1 Introduction...... 30 3.8.2 Transport System Upgrading ...... 30
4.0 REFERENCE CASE...... 32 4.1 Preamble ...... 32 4.2 Step A...... 35 4.2.1 Introduction...... 35 4.3 C4’s ...... 37 4.4 Integration in Step A ...... 38 4.5 Caveat ...... 38
- ii – 4.6 Heavy Gas Oil Step B...... 38 4.6.1 Introduction...... 38 4.7 Petro FCC...... 39 4.8 Heavy Gas Oil Hydrotreater ...... 41 4.9 Light Cycle Oil Recycle...... 41 4.10 Aromatic Complex...... 42 4.11 Integration of the Petro FCC and Aromatics Complex ...... 42 4.12 Miscellaneous Step B Additions ...... 43 4.13 Bitumen Processing Step C...... 43 4.13.1 Introduction...... 43 4.13.2 Conversion ...... 44 4.14 Conversion Product Hydrotreating ...... 44 4.14.1 Naphtha...... 44 4.14.2 Kerosene ...... 44 4.14.3 Diesel ...... 45 4.14.4 #2 HGO Hydr3otreater ...... 45 4.14.5 Gasification...... 46 4.15 Other Step C Additions...... 47 4.16 Step D – Fischer Tropsch Addition...... 48 4.16.1 Hydrogen and CO Rebalancing ...... 48 4.16.2 Incremental Ethylene Option ...... 49 4.16.3 Propylene ...... 49 4.16.4 Aromatics ...... 49 4.16.5 Alkylate...... 50 4.16.6 Diesel ...... 50 4.16.7 Naphtha...... 50 4.17 Utility Systems ...... 50 4.18 Storage Systems ...... 52
5.0 ENVIRONMENTAL ISSUES...... 53 5.1 Background ...... 53 5.2 Air ...... 55 5.3 Water ...... 56 5.4 Land...... 57 5.5 Greenhouse Gas Issues...... 57 5.5.1 Introduction...... 57 5.5.2 Site Emissions...... 58 5.5.3 Project Offsets...... 59 5.5.4 More Work Needed! ...... 59 5.5.5 CO2 Disposal Note ...... 59 5.6 Preliminary Economic Review...... 60
6.0 OTHER PROCESSING OPTIONS ...... 63 6.1 Introduction...... 63 6.2 Other Processing Options ...... 64
7.0 POSSIBLE DEVELOPMENT PROFILES ...... 69 7.1 Introduction...... 69 7.2 Siting and Access ...... 71 7.2.1 General...... 71 7.2.2 Corridors...... 71 7.3 Specialty Products Notes ...... 71 7.4 Arctic Gas and More NGL’s...... 72 7.5 Timing Factors...... 72 7.6 Different Order of Development?...... 73 7.6.1 Preamble ...... 73 7.6.2 In Step A Expedite New C2 C3 C4 Cracker ...... 74 7.6.3 Put Step B First ...... 74 7.6.4 Put Step C First ...... 74 7.7 Business Side Comments ...... 74
8.0 RESEARCH, DEVELOPMENT AND DEMONSTRATION...... 77 8.1 Introduction...... 77 8.2 Bitumen Supply Research & Development & Demonstration (R&D&D) ...... 82 8.3 Primary Upgrading Options...... 82 8.4 Pyrolytic & Catalytic Approaches to Ethylene, Etc...... 83 8.5 Integral Fluid Bed Cracking / Gasification Development ...... 83 8.6 Gas Separation Technologies...... 85 8.7 Extractive Technologies – Liquids...... 85
- iii – 8.8 Further Derivatives Research & Development ...... 86 8.8.1 Aromatics ...... 86 8.8.2 Non-Aromatics...... 87 8.8.3 CO2 Notes ...... 87 8.8.4 Biological Processing...... 88 8.8.5 Inorganics...... 88 8.9 Research and Development and Demonstration Economics Notes...... 88 8.10 Scale Up And Demonstration ...... 89 8.10.1 Introduction...... 89 8.10.2 Demonstration Stage...... 89 8.10.3 Lack of Large Pilot Units Here...... 90 8.10.4 Training ...... 90 8.10.5 New Development Facilities...... 90 8.10.6 Asian Cooperation – A Thought ...... 91 8.11 Research and Development and Demonstration (R&D&D) in Summary ...... 91
9.0 SUMMARY ...... 92 9.1 Introduction...... 92 9.2 Principal Products...... 92 9.3 Feedstocks ...... 92 9.4 Basic Process Scheme...... 93 9.5 Specialty Product Notes ...... 95 9.6 Balancing Petrochemical Monomer Supply/Demand ...... 95 9.7 Clues From Other Complexes ...... 96 9.8 Environmental Issues...... 96 9.9 Greenhouse Gas Issues...... 97 9.10 Basic A + B + C + D Yields...... 97 9.11 Economics ...... 97 9.12 Research and Development and Demonstration(R&D&D)...... 98 9.13 Conclusions ...... 98
10.0 CONCLUSIONS ...... 99
11.0 RECOMMENDATIONS ...... 102 11.1 Introduction...... 102 11.2 Basic Step Activation...... 102 11.3 Complex Siting and Regulatory Bases...... 105 11.4 Coordination ...... 105
GLOSSARY...... 106
REFERENCES ...... 109
ACKNOWLEDGEMENTS ...... 112
APPENDICES APPENDIX A TERMS OF REFERENCE APPENDIX B COMPETITIVE AREAS APPENDIX C KEMEX – ETHYLENE PRODUCTION APPENDIX D SFA PACIFIC GASIFICATION APPENDIX E LENEF CONSULTING – NATURAL GAS LIQUIDS
- iv – LIST OF TABLES PAGE Table 1.4-1. Chemical Cluster Overview ...... 4 Table 1.5-1. Atofina Feedstock Interfaces with Cracker and Metathesis Unit ...... 7
Table 1.5-2. C4 (Sabina) Plant Ownership...... 7 Table 1.5-3. Sabina Plant Capacities ...... 7 Table 1.6.1 Oil Sands to Petrochemicals Pricing Bases ...... 10 Table 2.6-1. Oilsands to Petrochemicals ...... 16 Table 2.8-1. Existing Ethylene Plant Byproducts...... 17 Table 3.8.2-1. Local Connections...... 31 Table 3.8.2-2. AIH/Strathcona Specific Interties...... 31 Table 4.1-1. Staged Development Approach...... 32 Table 4.2.1-1. Olefins Plant Ultimate Yields – 10,000 units by weight per hour feed...... 36 Table 4.7-1. Tentative Petro FCC Yields ...... 40 Table 4.17-1. Utility Concept Overview Æ PRELIMINARY Å ...... 51 Table 4.18-1. Storage Systems Æ PRELIMINARY Å...... 52 Table 5.2-1. Principal Air Quality Issues Today...... 55 Table 5.2-2. Air Quality Control in Proposed Core Facilities (a) ...... 56 Table 5.6-1. Overall Yields of Key Products ...... 60 Table 5.6-2. Very Preliminary – Internal Rates of Return and Net Present Values ...... 61 Table. 5.6-3. Capital Estimate - VERY PRELIMINARY -...... 62 Table 7.7-1. Steps A, B and C Technical Expertise Need Overview...... 75 Table 8.1-1. Stati of Process Development of Basic A, B, C, D Processes...... 77 Table 8.1-2. R&D Specifics...... 78 Table 9.10-1. Principal Product Yields...... 96 Table 9.11-1. Preliminary A + B + C Economic Analyses...... 97 Table 10-1. Comparison of Study Objectives ...... 98 Table 10-2. Technical Study Results ...... 99
- v – LIST OF FIGURES PAGE Figure 1.4-1. U.S. Steam Cracker Feed Stocks Year 2000 ...... 5 Figure 1.5-1. New Venezuelan Heavy Crude to Texas Petrochemical Monomer Trail...... 6 Figure 1.5-2. BASF Et Al New Port Arthur ...... 8 Figure 1.5-3. Air Liquide - USGC Pipeline ...... 9 Figure 2.3-1. Bitumen Outlook ...... 13 Figure 4.1-1. Envelope of Alberta Feed/Product Changes Development Considered in This Study...... 33 Figure 4.1-2. Core Fitting ...... 33 Figure 4.1-3. New Feeds / New Products By Step ...... 34 Figure 4.1-4. Complex Product Additions by Step...... 34
Figure 4.2.1-1. Initial Step C2 and C3 Processing Options...... 35 Figure 4.2.1-2. SGL Block...... 36
Figure 4.3-1. C4 Complex...... 37 Figure 4.6.1-1. Petro FCC Block...... 41 Figure 4.7-1. Petro FCC – Fluic Catalytic Cracking Unit...... 40 Figure 4.10-1. Aromatic Complex ...... 42 Figure 4.13.1-1. Bitumen Processing Block...... 43 Figure 4.13.2-1. Primary Upgrading Base ...... 44 Figure 4.14.3-1. Cetane Improvement Reactors...... 45 Figure 4.14.5-1. Basic Overall Flow Diagram ...... 46 Figure 5.1-1. Air Quality Concerns...... 53 Figure 5.1-2. Air Quality Concerns (Cont’d)...... 53 Figure 5.1-3. Air Quality Concerns (Cont’d)...... 54 Figure 5.1-4. Water ...... 54 Figure 5.1-5. Land...... 54 Figure 5.5.1-1. Greenhouse Gas Life Cycles Estimates...... 58
Figure 7.1-1. Major CO2 Distribution Grid ...... 70 Figure 7.1-2. 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 8.5-1. 3D with Excess Coke Gasification...... 83 Figure 10.1. New Venezuelan Heavy Crude To Texas Petrochemical Monomer Trail ...... 100
- vi – 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 – Study Ins/Outs Feeds Bitumen • Less than 10% of announced new bitumen production 120,000-BPD (in 2010) through 2010. Bitumen Derivative • Light ethylene and heavier Suncor and Syncrude 75,000-BPD (in 2008) hydrocarbons (synthetic gas liquids SGL’s) now burned in fuel gas streams (replaced in fuel gas with natural gas). • Heavy distillates excess to synthetic crude oil (SCO) needs 36,000-BPD (in 2008) from various upgraders. Refinery and Petrochemical • Small propylene and xylene-rich streams (largely from 5,000-BPD Byproducts SCO’s) from refineries. • Existing ethylene plant byproducts (now exported) and 8,000-BPD+ excess hydrogen (now in fuel gas) in exchange for natural 90 x 106 SCFD gas. • Some natural gas liquids (NGL’s) butanes (just enough to 8,000-BPD balance needs of one process). 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
C4 Alkylate • High octane, very environmentally friendly gasoline New 39,000-BPD component (Alberta, British Columbia and California markets). 1 Premium Jet Fuel and • Also very environmentally friendly (Alberta and British New 45,000-BPD Diesels Columbia markets) 1 Other Products Naphthas • Assumed routed to bitumen blending, but with alternates 25,000-BPD noted for conversion to more petrochemicals
CO2 • To new CO2 enhanced oil recovery. 30/35,000-BPD (More Alberta light crude) 2 1 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.). 2 No value placed on CO2 or added crude production in CO2 EOR.
- viii – 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 106 tonnes a year and the new petrochemical targets assumed in this study were in the order of 3 to 4 x 106 tonnes a year (even with other products, the total would only be in the order of 10 x 106 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/C3/C4 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 1 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 bitumen- processing 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 – C2 C3 C4 – cracker and the Petro FCC became the proxy for the original flexible feed cracker. (Alternates are available to convert naphtha to C2 C3 C4’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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 2 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
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 2012. 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 1.4-1 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 3 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 1.4-1. Chemical Cluster Overview
USGC HOLLAND SARNIA ALBERTA (AIH) Chemical Depth Mammoth High Small Shallow (Big Bulk/Simple) Industry in Breadth Mammoth Very High Fair Narrow General 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 Fair Good Excellent (but some lack of competitiveness) 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 (Marine) Long Pipeline OIL SANDS World 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) E3 only one Ventures Other Pipeline Grids – industrial Pipeline Grid – (some) Only a few Not Great gases, etc. plants close to 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 Great/Excellent Culture (partly isolated) Capital Costs BASE (High Environmental HIGH Above Base At/Base Protection Costs) BUT OIL SANDS OVERRUNS KNOWN WORLDWIDE Chemical CORE COMPETITIVE Core Competitive Low Little Competition Industry NON-CORE OPEN Non-Core Competitive Chemical GREAT! GREAT Minor NovaChem Research 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 4 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 1.4-1. Except relative to ethane, the importance of other derivatives is apparent.
Figure 1.4-1. U.S. Steam Cracker Feed Stocks Year 2000
% Total 1740 mb/d as % of C = 2 100 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]
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 5 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 1.5-1. New Venezuelan Heavy Crude to Texas Petrochemical Monomer Trail
Zuata Very Heacy Crude Total FinaElf 47%
PDVSA 38% 8.50oAPI Statoil 15%
Sincor Upgrader VENEZUELA
Ship 32o Premium SCO CARIBBEAN
Atofina 100% Port Arthur Ref inery Aromatics TE XA S Fuel Products Propy lene
World’s BASF * 60% Newest - Largest Atofina 40% Naphtha Cracker Ethy lene Various Derivative units at various sites Atofina Poly propylene Other C ’s C4’s Propy lene 4 BASF/Shell Poly propylene Other Products * (Basell)
Shell 60% Metathesis BASF * 50%? C4 Complex BASF 20% Unit Atofina 50%? Atofina 20% Buty lenes
Isooctane (to Gasoline)
Butadiene * BASF emphasizes “Verbund” - total integration of feeds/products into own or joint venture 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 C4’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
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 6 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 1.5-1. 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 1.5-3 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 1.5-2. C4 (Sabina) Plant Ownership
Shell 60% BASF 25% Atofina 16% Table 1.5-3. 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 C4 alkylate assumed produced in this study’s new complex.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 7 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 partners will get rid of their C4’s Shell will provide 66% of the feedstocks with the other partners providing the balance.
• BASF/Atofina Metathesis Unit
The C4 project has a second phase of metathesis, planned for 2003. 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 1.5-2. BASF Et Al New Port Arthur
? Many Other BASF Sites Atofina C = 2 Ethylene
C = Naphtha 3 Naphtha Propylene Cracker C4’s
Metathesis
Butanes (to cracking?) ? Other Users C4’s
Butadiene Dimer Extraction iC4=
Dimer HT Very High Octane H2 Alkylate
Butadiene BASF BASF Atofina 40% Product to Shell Joint Venture Atofina Atofina
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 8 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
Figure 1.5-3. 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 1.6-1. 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 9 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 1.6-1. Oil Sands to Petrochemicals Pricing Bases User selected Pricing Structure (Enter 1 or 2) 1 Exchange Rate: 0.65 Cdn $ US $ Cdn $ US $
PC's $0.03 below PC's $0.03 below Cdn $ Base Base Base Base
Pricing Stream Price Units Pricing Pricing Price Price in$/kT (as 12 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 $ 14.85 Bbl 263,179 $ 14.85 $9.65 $ 14.85 $9.65 Ethylene $ 0.34 pound 749,572 $ 0.29 $0.19 $ 0.26 $0.17 Propane $ 22.75 Bbl 282,677 22.75$ $14.79 $ 22.75 $14.79 Propylene $ 0.34 pound 749,572 $ 0.29 $0.19 $ 0.25 $0.16 n-Butane $ 24.50 Bbl 264,253 24.50$ $15.93 $ 24.50 $15.93 i-Butane $ 24.50 Bbl 274,187 24.50$ $15.93 $ 24.50 $15.93 Field butanes $ 24.50 Bbl 267,647 24.50$ $15.93 $ 24.50 $15.93 Diluent Naphtha $ 35.00 Bbl 320,333 35.00$ $22.75 $ 35.00 $22.75
C4 Alkylate $ 46.00 Bbl 407,766 46.00$ $29.90 $ 46.00 $29.90 Refy Naphtha $ 35.00 Bbl 220,462 35.00$ $22.75 $ 35.00 $22.75 Distillate Diesel $ 44.00 Bbl $ 44.00 $28.60 $ 44.00 $28.60 Fuel Oil $ 22.50 Bbl $ 22.50 $14.63 $ 22.50 $14.63 Benzene $ 76.87 Bbl 547,376 61.40$ $39.91 $ 47.20 $30.68 p-Xylene $ 0.37 pound 804,687 $ 0.32 $0.20 $ 0.27 $0.17 VGO $ 25.00 Bbl 160,589 25.00$ $16.25 $ 25.00 $16.25 Bitumen $ 15.00 Bbl 93,683 $ 15.00 $9.75 $ 15.00 $9.75 SCO $ 35.00 Bbl $ 35.00 $22.75 $ 35.00 $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 $ 22.50 Bbl $ 22.50 $14.63 $ 22.50 Other Feedstocks Price Units Price
Cracker C3 Stream $ 0.14 pound 308,647$ 25.43 per Bbl$ 0.14 $0.09 $ 0.14 $0.09
Cracker C4 Stream $ 0.12 pound 264,555$ 24.82 per Bbl$ 0.12 $0.08 $ 0.12 $0.08
Cracker C5 Stream $ 0.10 pound 220,462$ 22.75 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 C3 Stream $ 0.13 pound 286,601$ 23.49 per Bbl$ 0.13 $0.08 $ 0.13 $0.08 Cracker Butadienes $ 0.12 pound 264,555$ 26.99 per Bbl$ 0.12 $0.08 $ 0.12 $0.08
Cracker H2 Stream $ 1.50 MSCF 622,542 $ 1.50 $0.98 $ 1.50 $0.98 Refinery Xylene $ 47.00 Bbl 339,117 47.00$ $30.55 $ 47.00 $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%
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 10 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 • 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
1.7.1 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 375oC, 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 975oC. 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 11 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 2.3-1 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 12 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
Figure 2.3-1. Bitumen Outlook ‘000 b/day bitumen CNRL 300 1500 Shell 145 Black Rock 30 PetroVera 34
True North -Phase2 95 Conoco-Phillips 100 1000 Encana (CL-3) 30 CNRL 90 AEC 100 Encana (CL-2) 30 JCOS 50 True North -Phase 1 95 Anadarko 60 Husky/I.O. 20 500 Synenco 50 Rio Alto 30 Market Limit Encana (CL-1) 10 Deer Creek 30 about here. CNRL 115 ( Brintnell/Primrose/Wabasca)
~ 300 Current 0
01 02 03 04 05 06 07 08 09 10 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
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 13 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 + $0.50+ per barrel premium – partially deasphalted bitumen value 100 – Asphaltenes % Removed
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.)
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 14 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 C2 C3 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 C3, C4 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, C2= plus recoveries from Suncor and Syncrude olefin-rich fuel gas streams were assumed for analysis as in Table 2.6-1. 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]
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 15 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 2.6-1. Oil Sands to Petrochemicals Case Title Base Case Production Basis Recovery
Syncrude 370000 BPCD C2+
Suncor 330000 BPCD C2+ Totals 700000 BPCD
Total Production of SGL Components Annual Component BPD KTA
CH4 METHANE 5.8 335
C2H6 ETHANE 571.3 27,697
C2H4 ETHYLENE 106.8 4,881
C3H8 PROPANE 617.7 20,999
C3H6 PROPYLENE 312.7 10,344
n-C4H10 n-BUTANE 100.2 2,958
i-C4H10 i-BUTANE 49.1 1,503
C4H8 BUTYLENE 101.2 2,904
n-C5H12 n-PENTANE 41.7 1,139
i-C5H12 i-PENTANE 0.0 0
C6H14 n-HEXANE 41.8 1,085
C7H16 n-HEPTANE 0.0 0
H2S HYDROGEN SULFIDE 0.1 1
H2 HYDROGEN 0.0 1
N2 NITROGEN 0.0 0
H2O WATER 0.0 0 CO CARBON MONOXIDE 0.0 0
CO2 CARBON DIOXIDE 37.7 794 COS CARBONYL SULFIDE 0.4 3
CH3SH METHYL MERCAPTAN 3.4 65
C2H5SH ETHYL MERCAPTAN 0.9 14
C4H6 BUTADIENE 0.6 16
Totals 1991.4 74,740
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 C3 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 C2 plus SGL potential.
The Husky Lloydminster upgrader has some olefinic C3 C4 that could be recovered, but uncertainty about expansion plans and the need for rail delivery also deferred consideration.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 16 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 C3 C4’s
Regina Coop / New Grade Upgrader C3 C4’s – largely from catalytic cracking – were not considered, but should be considered in future studies, traded for C4 alkylate (much preferable) to their present use to produce poly gasoline.
However, at least one Edmonton refinery would like to increase the C4 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 C4 enhanced alkylate over the present C3 C4 alkylate would provide significant economic incentives.
This mixed C3 stream was arbitrarily valued at $23.50 Canadian per barrel.
2.8 Ethylene Plant C3 Plus Streams
A very arbitrary $0.12 Canadian per pound price was assigned to all C3 plus from existing plants, with this study’s very preliminary estimate of availability shown in Table 2.8-1.
Table 2.8-1. Existing Ethylene Plant Byproducts (KTA) (a) (b) Ethylene Production Assumed 4,000
C3’s C3= 120
C3 20 Other (Dienes) 10 TOTAL 150
C4’s C4= 120
C4’s 20 Butadiene Neglected TOTAL 140 Aromatic Concentrate Benzene 100 TX 30
C5’s 30 Others 10 TOTAL 170
Heavy Fuel Oil C9 Plus 20 Notes:
(a) Based on typical C2 cracking yields estimated by KemeX. (b) It is recognized that different units will have different byproduct streams with differing composition.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 17 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
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 106-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.)2
2.10 CO2 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 CO2 use / disposal schemes.
2.11 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.
2.12 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 C3 plus SGL’s in the present Suncor SCO line for added SCO and/or SCO components.
From Joffre a small C3 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. CO2 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 CO2 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 18 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 C4 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 CO2 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
3.2.1 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.
3.2.2 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 19 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 b) Pricing
May 2002 U.S. Gulf Coast contract ethylene prices were at $0.2375 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 $0.2375 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]
3.2.3 Propylene a) Demands
Currently, under 100-KTA of polymer, grade propylene is being produced by Williams Energy from Suncor C3 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 $0.2075 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 20 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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).
3.2.4 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 2002. 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.)
3.2.5 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
3.3.1 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
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 21 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 CO2 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.
3.3.2 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.]
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 22 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 2015. 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.
3.3.3 C4 Alkylate
In this study C4 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 CO2 per kilometer. However, C4 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 C4 alkylate will have lower octane
– 95 R + M compared to the 2 – 101 R + M of isooctane of produced by Alberta EnviroFuels’ and in 2003 by 2 BASF/Atofina in Port Arthur.
However, like the isooctane, the C4 alkylate is seen as having major West Coast markets. In Alberta and British Columbia C4 alkylate is seen as gasoline blending stock being traded for xylenes (for further processing to p-xylene) and refinery C3 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 C4 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.
3.3.4 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.
3.3.5 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 23 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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]
3.3.6 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!
3.3.7 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.
3.3.8 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 106-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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 24 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 CO2 a) Demands
Up to 15,000-TPD would appear “sellable” into CO2 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 CO2 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 CO2 to satisfy any/all urea needs. If CO2 disposal is needed its costs must be considered – here CO2 EOR use was assumed to result in zero netback, probably an underestimate.
3.6 Specialties
3.6.1 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 C4 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 • CO2 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.)
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 25 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 1000+ 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.
3.6.2 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 C4 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 C4 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 C4 complex could well revert to that noted above relative to the Shell BASF/Atofina C4 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 C4 alkylate. In that case, no C4 alkylate would be made with “in- house” butanes being cracked for more ethylene. This study did not estimate the overall impact or economics of such a change, But definitely recommends consideration.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 26 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 b) Dicyclopentadiene (DCPD) /Resin Formers
Available in the 20 to 50-KTA range, largely from ethylene production, currently, most of these move in C5 plus mixes to the USGC or Sarnia for further processing.
Extraction of cyclopentadiene and DiCyclopentadiene before hydrogenation of the C5 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 C1 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).
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 27 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 f) Other Heavy Aromatic Fractions
There are a wide variety of aromatics above C9 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 C10 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
CO2 • Distribute via major local and provincial grid, latter largely to CO2 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 28 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 H2S to sulphuric acid production (for Agrium needs) avoiding the current two-step H2S Æ Sulphur Æ H2SO4 route. Intriguingly, an H2S to H2SO4 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 C10 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 C4 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 CO2 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 29 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
Much current research is attempting to lead to new paraffin to high value derivatives, bypassing the olefin intermediate stage. A full range of C2 through C5 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
3.8.1 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.
3.8.2 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
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 30 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Strathcona County. Table 3.8.2-1 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 3.8.2-2 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 3.8.2-1. 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.
CO2 • Collector of CO2 from all major sources, routed to disposal and to two existing CO2 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.
Table 3.8.2-2. AIH/Strathcona Specific Interties Long Distance Pipelines
Strathcona C3’s • Strathcona refineries and AEF to new core SGL et al facility. Strathcona Naphthas • Strathcona refineries to new core. (optional)
Joffre Byproducts • New line from Joffre with NovaChem C3, C4 aromatic mix. Joffre Hydrogen • 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.)
CO2 Lines (optional) • 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 CO2 EOR potential and/or CBM prospects. Connect to Edmonton sources. (A CO2 line from Empress might be considered if CO2 is to be extracted there to enhance NGL capture.)
• (Note these are lines largely provide CO2 disposal service.) Western Clean Products • Strathcona to Edmonton to Kamloops/Vancouver parallel to TransMountain’s main line.
Line • (Revise existing line for crudes and SCO – perhaps C4 in last segment.)
• (This line would carry gasolines, jet fuels, diesels, isooctane, C4 alkylate (new), butanes (possible to U.S. refineries). (Consider for other materials – e.g., styrene, perhaps propylene.) SGL’s • New line from Suncor/Syncrude to core (branch from CNRL). • NGL’s from arctic gas to be commingled (future option).
Arctic Gas • Preferably with NGL’s (at least C2) extracted for use in new complex existing ethylene plants. Note: 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 31 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 2007. 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 4.1-1. Staged Development Approach
2007 / 2008 - SGL’s ex Syncrude and Suncor - Ethylene byproduct C3 C4’s Feeds - Refinery C3’s as available - NGL C4’s if/as needed Principal Products - Ethylene - Propylene - C4 Alkylate - SGL Fractionation - SGL C2 C3 Cracking Key Processes STEP A - C4 Olefins to C4 Alkylate • With core utilities and service operations, all planned to receive Step B and later Step C. • The C4 alkylate was selected as the only high-value C4 product from the SGL
feed – but some NGL butanes were needed to match the available butylenes in its production.
2008 / 2009 - Heavy Gas Oils / Vacuum Gas Oils ex upgrader New Feeds - Joffre H2 surplus - Ethylene Plant C5+
New Products - Much more Propylene - Benzene - P-xylene
STEP B - Naphtha - HGO Hydrotreat - Petro FCCU Key Processes
- Aromatics Complex • Again, each new step would be to design.
2009 / 2011 - Bitumen Processing New Feed New Products - Jet Fuel / Diesel - Hydrogen / CO2 - Bitumen Conversion - Distillate Hydrotreating New Processes
STEP C - Gasification • Most existing units would be expanded.
2009 / 2011 - Fischer Tropsch All Except H2 and New Products - Fischer Tropsch Naphtha CO from Step C - Fischer Tropsch Jet/Diesel - Fischer Tropsch Conversion
and Product Hydrocracking
STEP D
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
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 32 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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.
NEW Natural Gas Special D iluents & Synthetic Crude Oils Propane CHANGES AT (O ptional) NGL EXISTING ALBERTA C 4 ’s Naphthas Industry To C + Bitumen Production Ethylene 5 Expanded CO EOR Upgrading Propylene 2 & Etc. CO2 Refining P-xylene New (includes B.C.) Gasolines (alkylate) Alberta New Petrochemical Specialties Petro- Transport Jet Fuel and chem ical Fuel Syn Gas Diesels Related Industries Industries Users CO / H2 Western North America FIGURE 4.1-1 FIGURE 4.1-1. ENVELOPE OF ALBERTA FEED/PRODUCT CHANGES DEVELOPMENT CONSIDERED IN THIS STUDY
FIGURE 4.1-2. CORE FITTING
Suncor Bitumen Syncrude Production CNRL* Existing Light Ethylene Crude
NEW Added Petrochemical Demands for Natural ? New Local Consumers: Gas CORE Liquids FACILITIES Ethylene A / B / C Propylene Benzene Regional P-xylene R efineries (Specialties)
Upgraders
General Refined Diluted Bitumen Product Markets: PIPELINES Markets: TO SUIT Gasoline SCO’s Diluents Jet Special Blends Diesel
* Future
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 33 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
FIGURE 4.1-3 Natural Gas (Replacement) NEW FEEDS / NEW PRODUCTS BY STEP SGL’s Ethylene A Propylene Refined C3 ’s SGL et al Excess Alkylate NGL C4 ’s (Gasoline Cpt.) Dow/NovaChem Includes Existing SGL Facilities C 3 C 4 Cracker Specialties C 3 ’s/C 4 ’s INTEGRATION Upgrader HGO D iluents/Naphthas Purchased HGO Δ Ethylene B More NGL C4 ’s Δ Propylene Dow/NovaChem HGO PROCESSING et al Benzene A rom atics HGO HT Aromatics P-xylene Joffre H 2 Petro FCC Complex Specialties INTEGRATION Natural Gas (Replacement) SCO/Optional Bitumen Δ Propylene C Δ Benzene Δ P-xylene CO2 to EOR* BITUMEN CONVERSION Δ Naphthas More SGL’s Diesel & Jet Fuel Includes Air Specialties Separation H 2 / C O / N 2 D FISCHER TROPSCH Δ Naphtha Δ Jet/Diesel * Light Crude Produced. Many options in each stage. Ongoing Infilling and Expansion O ptionalin C A dded Ethylene E Specialties (all stages) O ptionalF Liquid C racker
FIGURE 4.1-4. COM PLEX PRODUCT ADDITIONS BY STEP A B C D E SGL/C2 C 3 Petro FCC/ Bitumen Fischer N/F C 4 C 5 /C 4 ’S Aromatics Conversion Tropsch 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 -- -- CO2 Minor -- Reduces -- Surplus H 2 -- -- (Uses) -- Sulphur -- -- -- N 2 -- -- -- -- 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”.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 34 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
4.2 Step A
4.2.1 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.)
Figure 4.2.1-1. Initial Step C2 and C 3 Processing Options Ethy lene SGL C2’s Ethy lene * Ethane
Existing Ethane Crackers (at 10% of nameplate)
* * New C2 Cracking New 800-KTA New C3 Cracking Gas of * Cracker Ethy lene Merchant Market Propane Hydrogen SGL C3’s & Propylene * Petr oc hemic al Pr opy lene H2 Plant C3 Dehydrogenation Propylene
* Selected for basic plan. Cy c lar 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 CO2 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 C2 C3 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 C3’s are very largely propylene and refinery C3’s 65 to 70% propylene. (The small quantity of propane from these feeds was considered in C2 C3 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
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 35 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 CO2) and fractionation and the C2 C3 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 C2 C3 gas cracker configuration and Table 4.2.1-1 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 4.2.1-1. Olefins Plant Ultimate Yields – 10,000 units by weight per hour feed (kilograms or pounds)
H2 CH4 C2H4 C3H4 C3H6 C3H8 C4C6 C4H8 n-C4H10 C5’s Benzene Toluene X-EB Gasoline Fuel STYR Oil Ethane 676 635 7701 3 231 33 188 33 43 90 196 31 20 75 36 Propane 177 2779 4526 0 1510 Recycle 230 92 5 120 272 63 61 123 41 n-Butane 132 2208 3998 50 1647 22 349 171 501 164 270 111 51 124 201 Naphtha 110 1624 3168 84 1462 1 457 379 78 359 672 429 362 498 309 Gas Oil 79 981 2401 29 1356 1 483 537 7 547 400 271 198 673 2032 70 / 30 n / 134 2244 3284 100 1766 24 310 545 n 376 176 288 121 58 173 201 isobutane i 200 Source: KemeX – See Appendix C
FIGURE 4.2.1-2 A SGL BLOCK (& Gas Cracker) EXTRACTON + Design all to accommodate B, AT SITES C parts of D additional feeds. (Surplus) NovaChem C3 C 4 Refinery C ’s 3 (Surplus) Dow C3 ’s Refinery C 3’s
CO2 (Small)
NGL C 2 = ETHYLENE C 2 Common
Propane or Butane C * 3 Fractionation (To Balance) Cracking C 3= PROPYLENE Purification
C ’s C ’s Optional 4 4 To/From B&C nC4 C Alkylate HT Alkylation 4 (2) Fixed Bed Dow nC4 C 4 ’s
x le p C 4 m o Isomerization C * Integrate C3 = with C 4 W illiam s Energy NGL C 4 ’s
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 36 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.3 C4’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 C4’s) or in dilutes from (all C4’s to alkylation).
The production of C4 alkylate was selected as appropriate given the prospective new (BC) gasoline market – and California opportunities and the very excellent properties of C4 alkylate – octane 96 (above that of 87 regular gasoline), no aromatics, no olefins and no sulphur – almost smog free fuel.
FIGURE 4.3.1. C4 COMPLEX
TO GAS CRACKER n Butane Propane if available to cracking
C 4 Splitter
Deprop i/n C4 Field C4’s C nC 4 4 Isomerization
Ethylene Bulk HT Plant C4’s nC4 /C 5 iC4
H FCC 2 Trim HT C Alkylation Debutanizer Other C 4’s 4 C 4 C 4 Alkylation to Market (45/50/bbl) Deep C 4+ from Naphtha + SGL Deprop Debutanizer Future C 4 to SCO Only Blends Naphtha Naphtha to Optional Hydrotreater Corunna Naphtha to Upgrader Other C Diluent Naphtha Unhydrotreated Hydrogen Naphtha to Naphtha’s Petro FCC (Future) (C) 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. H2SO4 is used in a Vancouver unit, but has very high acid makeup and regeneration rates introducing SO2 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 nC4 from the alkylate product. [16]
The paraffinic C4’s from SGL’s etc. are largely n-butane and the alkylation needs i-butane:
C4 H8 + iC4 H10 Æ C8 H18 (any nC4H10 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 C2 C3 (C4) cracker.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 37 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
As discussed later, prior butadiene extraction for sale should do definitely be considered in further studies. Its revenues and reduced NGL C4’s should offset decreased alkylate and capital costs may be little different.
The initial C4 complex would be planned to process the large C4 volumes from the Petro FCC of Steps B and C.
4.4 Integration in Step A
While three process segments – SGL fractionation, C2 C3 cracking and C4 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 C4 C3 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 C5 plus portion of the SGL’s may require a small hydrotreater before the C5+ product can be moved to diluent and other markets. This C5 plus stream would be routed to the feed hydrotreater of the aromatic complex in Step B.
4.6 Heavy Gas Oil Step B
4.6.1 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 106 of hydrogen (with 10 x 106 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 4.2.1-1 above.
With the C2 C3 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 38 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
FIGURE 4.6.1-1 B PETRO FCC BLOCK (& Aromatic Complex)
C 4 - C 5 A Sulphur
C -C Naphtha Diluent / H 5 7 Sulphur Plant * FGD * 2 Sarnia / Other ?
HGO’s 36,000 Hydrotreater Petro C 5/C 9 Hydrotreater VGO’s 2-Stage FCC * Aromatic Benzene Light Cycle Oil Heavy Complex P-Xylene (Recycle) Aromatic C 10/11 Compounds Heavy Aromatics Aromatics C 12+ Aromatics (Traded for HGO)
Joffre Gasification Ethylene Specialties H 2 (default) in Plant C5+ (Future) C only * Design 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.
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 C3 C4 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 SO2 to necessitate the ammonia type flue gas desulphurization assumed here. The hot – 750oC – 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 39 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
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 C3 C4’s and light aromatic derivatives. Again, this is an item requiring attention.
Table 4.7-1. Tentative Petro FCC Yields Yield Weight % Yield Note Product KTA at 35,000-BPD Petro FCC
H2S, H2, C, C2 3.0 Route to Ethylene Plant Ethylene 6.0 110
Propane 2.0 Route to C3= Purification Propylene 22.0 400 Butanes 5.0 Route to Alkylation Butylenes 14.0 255 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.
FIGURE 4.7-1. PETRO FCC - FLUID CATALYTIC CRACKING UNIT C 2 - to C2 C 3 Cracker Frac Stack Separator Stripper Gas C 3 to C 3 = Purif. Kiln Plant C 4 to Alkylation FGD Flue Gas B F R C 5 + A Recycle Riser C Reflux Reactor T Steam I Heavy Naphtha to Steam O Aromatic Complex N Spent A T Light Cycle Oil HT Recovery C Catalyst O Air R BFW Hot Steam H 2 S, C5 - Catalyst Feeds Heavy Aromatics C + Vacuum A 12 30/36,000-BPD A Purge Heavy HT 70 to 80,000-BPD Gas Oils 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 C3 =, C4 = Two Risers Possible B Flue Gas Desulphurizer - common with Sulphur Recovery?, Ammonia-based - 99.9% Capture (Marsulex). C LCO recycled to partially saturate multi-ring aromatics - with further cracking in FCCU to produce C6 -C 9 aromatics. D Naphthalene extraction to be considered.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 40 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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.
+ C3, etc. + H2
Naphthalene Decalin Benzene Hydrotreat Cracking
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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 41 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.10 Aromatic Complex
Figure 4.10-1 outlines possible configuration of new facilities to process the Petro FCC’s light aromatic- rich streams and C5 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 4.10-1. AROMATIC COMPLEX
Paraffinic Naphtha Streams C5 C6 Benzene * Toluene Toluene H C 6 C 5 HDA 2 Various Ethylene C6 C7 Solvent Refinery Raw Plant Extraction Benzene BTX Depent. Benzene Naphthas C 5 + Tower Toluene A Splitter Naphtha Toluene Hydrotreater Tower
Toluene/C Refinery 9 Toluene C 9 Disproportionation Xylenes to Xylene’s A 9
P-Xylene Para-Xylene Adsorption Xylene A 9 Column Column Xylene H 2 Isomerization
C 10 + Aromatics B (some to Petro FCC DCPD/Resin Former system probably needed. A LCO Recycle?) B O-xylene tower goes here if o-xylene product.
* 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 C9+ 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 C9+ 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.
4.11 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 42 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 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 / C2 / C3 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
4.13.1 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.
FIGURE 4.13.1-1 C BITUMEN PROCESSING BLOCK
Bitumen C 3 C 4 to A 120,000-BPD
Naphtha Naphtha Naphtha C rude D istillation Hydrotreater
Kerosene Kerosene Jet (M arket) PRIMARY Hydrotreater THERMAL Diesel SIM PLE Diesel Diesel (M arket) Hydrotreater
* HGO Other HGO Pitch(es) Hydrotreater #2 Low Value ~ Materials Gasification Sulphur Exp.
Ash HGO B O Petro FCC 2 Hydrotreater #1 BLOCK Air Syn Gas H Separation Shift 2 N 2 H 2 to Sale CO2 D CO2 to CO EOR BLOCK 2 Fischer Tropsch Liquids
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 43 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.13.2 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 4.13.2-1. PRIMARY UPGRADING BASE
DEEP VISBREAKING OBJECTIVE • M inimal loss of paraffinic branches, etc. • M inimal production of aromatics/asphaltenes. • M inim um m etals to further steps.
Sour Gases
Naphtha Fractionation Decoke Heater Every 3 to 4 months M id D istillate
TRAIN A Soaker Vacuum Heater Distillation
NOTE PLACEHOLDER PROCESS ONLY TRAIN B Pitch to G asification
4.14 Conversion Product Hydrotreating
4.14.1 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.
4.14.2 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 44 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.14.3 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 4.14.3-1 (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 4.14.3-1).
FIGURE 4.14.3-1
4.14.4 #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 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.] 7 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.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 45 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
4.14.5 Gasification
The largest units in the bitumen processing block will be the gasification unit, its associated air separation unit and synthesis gas (syngas) clean-up. Figure 4.14.5-1 reviews the suggested gasification route through wet syngas to hydrogen production, with balances for an arbitrary 30,000-BPD of pitch feed rate. Appendix D goes into more detail on the proposed system gasification and extensive commercial experiences.8
Figure 4.14.5-1
B a s ic O v e ra ll Flo w D ia g ra m --P ro d u c tio n o f Hy d ro g e n v ia G a s ific a tio n o f B itu m e n D e a s p h a lte r B o tto m s 30,000 BPD of Pitch Reference Case *
CO2 32,400 moles/hr 284 M M scf/d Δ CO = 23,500 lbmole/hr Δ CO = 4,500 lbmole/hr tail gas DA Bottoms 30,000 bbl/d, 5,573 mt/d O2-Sulfur Sulfur 500°F 400°F Recovery 390 mt/d Steam High- Low- pure 3 uints 256,000 lb/hr, 2,787 mt/d Temp. Temp. CO2 Shift Quench W ater Shift Air Oxygen 2,900 lb mo le/h r 800°F 480°F PSA Separation 5,573 mt/d 52 M lb/hr H 2 u nits 2 u n its 2 stage 2 units 2 Q = 1,100 S e le xo l 459 MM scf/d Q = 45 Steam, 260 M lb/hr Q = 100 A GR Q = 270 2 units 4 750°F Quench 500°F 400°F Gas ifers Water 900 psig 37,296 moles/hr L.P. Vent to Fuel 2,300°F A bove steam and heat is used for misc internal uses like acid gas stripping 671 M lb/hr 496 MM Btu/hr Quench W ater 450°F Only major utility import is electric power for air separation unis & misc. 248 50,000 lbmole/hr 900 M lb/hr, 9,800 mt/d 1,200 psig PSA fuel gas steam steam boilers to gasifier 275,000 lbs/hr Soot 168 mt/d 2,7877 mt/d A sh 67 mt/d W ater 1,120 mt/d Notes 1,355 mt/d M = thousands mt/d = metric tons/day Q = MM Btu/hr
* A ctu al thro ug hp ut d iffers .
Source: SFA Pacific, Inc. June 21, 2002
8 Figure 4.14.5-1 is a SFA Pacific Inc. overview of Shell Pernis Gasification of visbreaker pitch from an earlier SFA Pacific presentation to the sponsors. At Pernis Shell use synthesis gas to fuel a one gas turbine cogeneration system when all three gasifiers one on line. Whenever, a gasifier is out for maintenance natural gas is used as gas turbine fuel to maintain hydrogen production from synthesis gas. The use of synthesis in a gas turbine requires injection of steam and/or nitrogen to lower the flare temperature to keep NOX at a reasonable level. Today’s large gas turbines all have dry low NOX combustors achieving even lower NOX without any such injection. We assume steam injection at Pernis; the air separation unit providing the oxygen is some distance away. As noted elsewhere there will be severe concerns about any/all water withdrawals for any new complex such as suggested here. Steam injection adds a significant steam plume on high humidity days. Thus, steam injection is not particularly desirable. The use of synthesis gas in lieu of natural gas is gas turbines results in approximately three times as much CO2, say, 0.75-kg CO2/kWh of electricity output in a high-efficiency cogeneration setting compared to 0.25 for natural gas. The better coal plants can get below 0.9 and Epcor has been required to buy offsets down to the order of 0.36. Thus, the use of synthesis gas for electricity production – or for any fuel use – is not recommended, except in an emergency.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 46 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
The gasifiers react heavy liquid residue with oxygen and steam to produce a raw hydrogen (H2) carbon monoxide (CO) syngas and a small amount of carbon-rich ash, which contains all the metals in the feed. The hot raw syngas is cooled (raising steam) and then the CO is reacted with steam to CO2 and more H2. The CO2 and sulphur compounds are removed and a final clean-up (PSA / equal) used to raise the hydrogen purity to 99.5%, with purge to plant fuel gas.
The gasifier system proposed here is quite similar relative to feed gasification and hydrogen production in the relatively new Shell Pernis refinery system. [20] The main differences would be onsite air separation here versus offsite in Pernis and use here of a lower temperature quench approach versus high-pressure byproduct steam generation before adding steam for the quench reactions leading to hydrogen. Here the quench gasification approach has been assumed due to lower capital costs and provide the appropriate wet syngas for hydrogen. This lowers thermal efficiency slightly and byproduct steam pressure but should ensure higher overall reliability. The shift operation will also produce byproduct steam, but all needed onsite. Air separation is very reliable, but two air separation units are very likely (with six or so gasifiers) – as roughly 6,200 tonnes per day of oxygen will be needed and the world’s largest current designs are in the order of 3,500. There are already two, large by conventional standards, air separation units between Fort Saskatchewan and Scotford and some pipeline integration should be considered as backup.
Multiple gasifiers provide a high level of reliability in an often-difficult process, allowing lining and/or inlet distributor (burner) repair as required, with some stockpiling of feed. (The Joffre hydrogen supply will prove ideal at such times to make up for reduced gasifier output.)
The gasifier could also be fed waste oils from onsite and perhaps from offsite sources – e.g., surplus (to HGO trade) highly aromatic heavy fractions from the FCCU and/or aromatic complexes and any polymers from butadiene partial saturation in the C4 complex. It will also be able to take waste (sour) gases from most units in case of emergency or routinely if appropriate (with compression to the 60 bar gasification pressure).
The gasification units will have extensive wastewater treatment facilities with maximum recycle. The ash from gasification will be routed to landfill initially, but could well be processed along with vanadium and nickel-laden catalysts from three Alberta and two Saskatchewan residual hydroprocessing units. (Such an operation would be an ideal special unit / plant add-on.)
4.15 Other Step C Additions
Virtually all prior units in the complex will be expanded and integrated with bitumen processing with the C4 alkylation, Petro FCC, aromatics and propylene purification and sulphur capture (including flue gas treating) receiving the bulk of attention.
Step C includes a major onsite electricity generation component to provide the needs of air separation. As noted later, a steam surplus is possible and some new steam-based generation is likely. The gasification complex will include major makeup water treating and wastewater treating / recycling systems.
Major new tankage will also be needed, as noted in a later section to handle the new jet fuel and diesel products and added naphtha, alkylate, aromatics and perhaps propylene.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 47 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.16 Step D – Fischer Tropsch Addition
4.16.1 Hydrogen and CO Rebalancing
As seen in the data for Case I in Table 5.6-1 there is a major surplus of hydrogen, as well as of CO2 produced in the basic scheme. While there are sales opportunities for part of the hydrogen – and as discussed later, it could well find good homes in hydrogenation of raw SCO’s from the field – the amount appeared excessive to a base case. Thus, addition of a synthesis gas conversion step was considered.
There are “almost at commercialization” processes available to convert synthesis gas-based methanol to light olefins – the first commercial methanol to primarily ethylene project was just announced for Egypt. [21] However, a more direct Fischer Tropsch to diesel route was selected for consideration here.
CO + 2 nH2 Æ (CH2) n + nH2O
This route would significantly reduce CO production as its carbon is transferred to Fischer Tropsch liquid (and some fuel gas). It would also greatly reduce shifting CO to hydrogen.
CO + H2O Æ CO2 + H2
(While the raw synthesis gas composition is roughly 50 / 50% CO and H2, some Fischer Tropsch processes accept a lower ratio than the appropriate 2.1 H2 / CO, shifting CO (to H2 and CO2) as needed to balance the Fischer Tropsch reaction. Alternately, the correct ratio can be developed by prior shift (with / without CO2 removal). The addition of Joffre hydrogen to gasification syngas is an excellent approach to adjusting the CO / H2 ratio.
Sasol has developed Fischer Tropsch processes over many years – from coal, but natural gas reforming appears their new base. Shell has a unit in Malaysia and new very large Fischer Tropsch process units are going into Nigeria and the Mid East. However, it would be noted that good yield utility and capital data are proprietary in most cases and only preliminary estimates were possible here. Most of these processes use process gas recycle, but here where much hydrogen is needed for hydrogenation a partial conversion once through system appears appropriate. In the assumed Fischer Tropsch version, the raw Fischer Tropsch liquids tend to be higher boiling and have minor oxygenate and ∝-olefin components.9 The latter are removed and the boiling range and cold flow properties are adjusted in a hydrocracker to, say 30% paraffinic naphtha and 70% very premium jet fuel and diesel, albeit very low in density.
The Fischer Tropsch facility will produce significant medium pressure steam for other parts of the complex and also recover much water in its reaction and reduced CO shift will also lower net water consumption.
The yield of Fischer Tropsch naphtha and diesel is significant – in this base case with high pitch rates – approximately 24,300-BPD, 20% of the 120,000-BPD of bitumen, a very appreciable increase in yield.
However, the Fischer Tropsch naphtha is unlikely to be desirable as bitumen diluent, but an ideal naphtha cracker feed assumed here as routed to a naphtha cracker – e.g., NovaChem’s Corunna unit – but at $5.00 off Edmonton par crude reflecting its qualities. The jet / diesel is expected to be blended with similar boiling range materials from jet and diesel hydrotreaters, with a premium of $2.00 per barrel for very high smoke and cetane qualities.
Note: Without Fischer Tropsch the CO2 product could result in a maximum of very roughly of new light crude 80,000-BPD. With Fischer Tropsch the maximum would still be in the order of 45,000- BPD.
9 It is possible to produce mostly light olefins via certain version of Fischer Tropsch, but usually with high methane coproduction. Such routes must be considered in further studies.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 48 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
4.16.2 Incremental Ethylene Option
In developing the basic process scheme, the new C2 C3 cracker would be at only two-thirds of a new world-scale unit. A trial was run to see if adding purchased propane would be attractive. The economic evaluations came up marginal, unless below average propane could be purchased – this may well be feasible via purchases when propane prices are low and storage over high priced seasons.
Naphtha cracking was not considered, as the cracker’s recovery directly requires major revision and the initial feed / product analysis indicated high naphtha values – too high to directly compete with propane or butane.
As discussed below, there are options to convert all internally available naphthas to propane, butanes (usually with high iso content), and, in some options, to added aromatics. The propane would go to cracking and the butanes to alkylation. Disproportionation of propylene to ethylene and butylene – the reverse of the metathesis process being added at Port Arthur – is quite feasible to increase the ethylene / propylene production ratio. (The two processes can use essentially the same equipment, changing catalyst and reaction conditions to suite.)
4.16.3 Propylene
The Petro FCC unit is the major propylene source, but the SGL’s themselves will provide most propylene until that unit is on line.
The severity of C3 cracking can be reduced when there is room in the new C2 C3 cracker’s gas recovery and C3 distillation systems to match the added C3 recycle stream. The reduced severity will increase propylene yield, partly at the expense of ethylene – the total will be marginally higher than at maximum ethylene.
Added propylene could also be made by metathesis as in the new Port Arthur Sabina unit discussed earlier from ethylene and butylenes. This would require revisions in the C4 complex, as laid out here.
Propane can be catalytically dehydrogenated in a well proven process, if/as appropriate. This was modelled, but did not appear to fit.
4.16.4 Aromatics
Mixed xylene dealkylation to benzene is practiced (occasionally) at the Scotford refinery.
C8H10 + 2H2 Æ C6 H6 + 2CH4
The high hydrogen demand and low weight yield – say 70% when losses are considered are often against the economics of such a route. However, the aromatic complex will almost certainly have a toluene dealkylation unit for balancing, but toluene transalkylation with C9+ aromatics to xylenes is likely.
C7H8 + C9 H10 Æ 2 C8 H10
If para-xylene demands are high. Transalkylation is a relatively common, well proven process. For example, Zeolyst recently introduced a new catalyst; this is an area of intensive catalyst development towards better yield structures and more robust catalysts. [22] [23]
Note: This study did not attempt to model the many unit options available and developed a very simplistic benzene / p-xylene yields from various aromatic-rich streams.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 49 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.16.5 Alkylate
As noted, several times butadiene extraction may be best economically, automatically reducing alkylate yield. Dimerizing isobutylene before n-butenes alkylation is another way to decrease alkylate, at the same time increasing the value via an isooctane / C4 alkylate blend. This route needs consideration, especially, if a LPG oriented hydrocracker is installed as expensive butane isomerization and separation could be avoided at the same time backing out all NGL C4’s.
4.16.6 Diesel
(See above re Fischer Tropsch addition.) There is some room to transfer diesel boiling range fractions from the hydrotreated Petro FCC feed via reprocessing in the diesel hydrotreater. Conversely, hydrotreated diesel can be added to the Petro FCC. Raw Fischer Tropsch residues can be very easily cracked to light olefins in the Petro FCC if desired, but that is seen as a last resort.
4.16.7 Naphtha
This study did not try to measure the potential of naphtha addition to the Petro FCC cracking system to increase propylene, butylene and light aromatic yields. However, such study will be of high importance in all future studies / planning re the Petro FCC – its R&D activities must always keep naphtha injection in mind.
Some consideration was given to putting C5’s into the new C3 C4 cracker, but the potential qualities without major unit change appeared minor and thus not employed in any depth.
However, it is quite feasible to convert all sulphur, pentanes, naphthas to C3 and iso-rich C4 via a simple LPG hydrocracking. In such a route, the propane would go direct to the C2 C3 C4 cracker and the C4 to alkylation backing NGL purchases and/or reducing/eliminating the need for n-C4 to i-C4 isomerization. This semi-direct naphtha to ethylene route appears very likely to cost no more than adding naphtha cracking, provides added process flexibility, and simplifies ethylene production.
However, the Petro FCC can crack naphthas to olefinic C3’s and C4’s, so that there would be added flexibility in naphtha product elimination. (Further study may show high ethylene possible in certain Petro FCC configurations.)
In practice, all naphthas can be consumed in new bitumen to petrochemicals complex without naphtha furnace cracking using proven technologies.
Note: This study only noted such opportunities rebalance the product slate. More definition of new petrochemical monomer market.
4.17 Utility Systems
This study did not go into depth relative to utility systems. However, internal self-sufficiency on steam and electricity was assumed as a base, except for electricity and steam purchases at SGL extraction sites. No electricity sales were assumed, as base load electricity unlikely to be of significant value, given coal competition, and no surplus internal fuel gas was noted unless synthesis gas is burned. But the hydrogen in the latter was assumed sold and the CO converted to more hydrogen and CO2. Use of synthesis gas is to be avoided in small-scale gas turbine generation due to difficulties in NOX control, but can be considered in large frame machines using nitrogen addition (with steam if needed) to control NOX; (but experience meeting CCME NOX guidelines was not analyzed in this study).
In this study, no use of synthesis gas for cogeneration or even in-fired heaters is proposed. Burning synthesis gas results in about three times as much CO2 as does burning natural gas indeed synthesis gas
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 50 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 is little better than coal. Epcor and TranAlta’s proposed coal-fired generation expansions will be required to buy CO2 offsets to lower net CO2 to that from combined cycle natural gas generation – well under that achievable with synthesis gas from the gasification unit.
The value of synthesis gas is estimated at above natural gas and on equivalent energy basis, when used to produce hydrogen for onsite use and/or sales. However, here all available hydrogen is assumed reacted with CO in synthesis gas to produce Fischer Tropsch liquid products. Fuel gas balancing has assumed natural gas makeup.
As noted in Environmental Issues, there will be very close scrutiny of all proposed new / revised facilities in the region selected as a “logical” new complex site. The 40-MW gas turbines noted above possibly should be changed to one or more 80+MW machines to get their NOX down to the 9-ppm level – currently unavailable on the aero derivative machines unless expensive selective catalytic NOX reduction is added.
Utility development will follow the long-term development plans to optimize capital over time. The program now foreseen for Steps A, B and C is shown in Table 4.17-1, but its preliminary nature is to be noted.
There is concern about the large quantity of makeup water needed in gasification. Conversion of excess hydrogen to Fischer Tropsch liquids will recover significant portions of that makeup – this becomes a major non-economic raison d’être for such a unit.
There is also concern that the very high greenhouse gas emissions when synthesis gas is used to generate steam or electricity. This study did not consider use of synthesis gas in cogeneration.
Table 4.17-1. Utility Concept Overview Æ PRELIMINARY Å A B C / D Electricity • 40 or 80-MW Gas Turbine Cogen • 40 or 80-MW Gas Turbine Cogen • 80-MW Gas Turbine Cogen plus 40- Steam • 1-MW Emergency Generator • 1-MW Emergency Generator MW Steam Turbine Generation. • (Note C2C3 cracker has its own • (Note C2C3 cracker has its own • (Note gasification has its own steam steam systems – slight surplus, with steam systems – slight surplus, with systems balanced in current plan electricity from core utility unit.) electricity from core utility unit.) with electricity.) Water • Water supply for A, B and C • Expand Supply. * Supply complete with large pond. • Fire Water System for A complete • Extend Fire Water • Extend Fire Water with Diesel Pumps. • BFW for all boilers. • BFW for B. • BFW for C. • Condensate System. • External Condensate System. • Second Condensate System. Waste Water • C2C3 Cracker Internal • New biopanels, etc. for FCC • Gasification Wastewater Treating • Central Water Recycling System. wastewater. System. • Extend Recycling System. • Expand Recycling • Collect/Treat/Reuse all Fischer Tropsch Water. Nitrogen • Pipeline Supply to Distribution Grid. • Extend Grid. • Feed grid from air separator. • Extend to plant air system. • Consider some LN surge storage. Instrument / • 2 x 500 SCFM Compressors + Drier • 1 or 2 added compressors and • Use nitrogen with compressor / drier Plant Air (N2 backup) drier. backup. Solid Wastes • Short-term storage (to landfill). • Added short-term storage for spent • Special short-term storage for FCC catalyst before move to offsite gasification ash before movement to landfill. offsite landfill or reprocessing.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 51 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 4.18 Storage Systems
Table 4.18-1 provides a very preliminary review of the wide variety of storage now anticipated in Steps A, B and C.
Table 4.18-1. Storage Systems Æ PRELIMINARY Å Stream Type A New in B New in C Note SGL Caverns 2 @ 300,000 each -- -- Add if needed Bullets 1 @ 2000 bbl -- -- Use for rail, misc. recycle
C2 Cavern (existing) -- -- Balance with NGL C2 C3 Cavern 1 @ -- -- Balance with NGL C3 nC4 Cavern ? Consider ? -- Only if nC4 to cracking Raw C3 Bullet 2 @ 1000 bbl -- -- Raw C4 Bullet 2 @ 1000 bbl -- -- Raw C3 C4 Bullet 2 @ 1--- bbl -- -- Raw C3+ Refrig. Tk. -- 1 @ 100,000 bbl -- Raw Xylene Std. Tk. * B -- 1 @ 10,000 bbl --
C2= Cavern (existing) -- -- C3= Cavern Add 1 @ 300,000 Add 1 @ -- Benzene Std. Tk. * B -- 3 @ 30,000 -- P-xylene Std. Tk. * B -- 3 @ 20,000 --
C4 Alkylate Std. Tk. 2 @ 20,000 1 @ 50,000 1 @ 150,000 Note full rate pipeline delivery Naphthas Std. Tk. (F) 1 @ 10,000 1 @ 150,000 2 @ 100,000 Consider more tanks Jet Std. Tk. -- -- 2 @ 100,000 Diesel Std. Tk. -- -- 2 @ 200,000 Raw HGO Std. Tk. (Heat) B -- 1 @ 200,000 1 @ 200,000 HT HGO Std. Tk. (Heat) B -- 1 @ 200,000 1 @ 200,000 LCO Std. Tk. B -- 1 @ 30,000 -- HCO Std. Tk. -- 1 @ 50,000 1 @ 50,000 Hy Aromatics Std. Tk. * 1 -- 1 @ 50,000 1 @ 50,000 Pitch Hot Tk. B -- -- 2 @ 200,000 Spare / Slop Std. Tk. * B 1 @5,000-BPD 2 @ 10,000 2 @ 10,000 FT Naphtha Std. Tk. (F) -- -- 1 @ 50,000 in D FT Diesel Std. Tk -- -- 2 @ 60,000 in D * Special treatment of vapour space. (F) Floating Roof. (B) Blanketed (N2)
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 52 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 5.0 ENVIRONMENTAL ISSUES
5.1 Background
Figures 5.1-1 through 5.1-5 provide a very quick overview of specific environmental concerns in Alberta with specific relevancy to the proposed new facilities. Greenhouse gas issues have been split off from this discussion, as it is a global issue; here we address only Alberta specific challenges.
Cumulative emissions, especially to air and water, are of major and growing concern in the oil sands area and in the Redwater / Fort Saskatchewan area. This is to some extent a catchall item to environmentalists, based on increasing industrial activity inferring increasing emissions.
FIGURE 5.1-1 AIR QUALITY CONCERNS
NO Cumulative X Mining SO Emissions 2 Industry HC’s Concern Generation Areas Particulates
Edmonton ? Red Deer
FIGURE 5.1-2 AIR QUALITY CONCERNS (Cont’d)
Urban Smog NOX Concern HC’s Areas (SO2) Particulates Ozone NO Concern X HC’s Edmonton Area
Calgary
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 53 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 FIGURE 5.1-3 AIR QUALITY CONCERNS (Cont’d)
Greenhouse Gas CO2 Constraints CH4 N2O
P General Oil Sands
Coal Generation General Oil & Gas P & Gas Pipelines
P P P - Chemical Industries
FIGURE 5.1-4 WATER
N
Serious Withdrawals (& losses) for: Ground Water • Agriculture Concerns • Conventional Oil •IN-SITU Major River • Oil Sands Withdrawal • Power Generation Concerns S
Boundary Issues: Reduced Flows: Serious S Saskatchewan • Climate Change Water Use • Enhance Non-Return Uses S N NWT Concerns Returned Water Quality M U.S. ? • Concentrate Impurities M • Add Impurities Animal Wastes
FIGURE 5.1-5 LAND
Disturbances: • Oil Sands (Long Delayed Remediation) • Conventional Oil & Gas •Power Lines
Withdrawal: • From forest, etc.* • From agriculture
*Note changing long-term vegetation patterns due to climate change.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 54 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
5.2 Air
In the oil sands area, particulates and acid deposition are of most concern air wise – particulates due to connections to public health and acid deposition – SO2 + NOX – due to sensitive soils and lakes as one approaches the Canadian Shield just on the Saskatchewan border. In the area northeast of Edmonton, smog – urban haze is a challenge, but one largely due to coal-fired power plants west of Edmonton with prevailing winds moving emissions over Edmonton, and especially along the river valley towards Fort Saskatchewan.
Ozone has seldom been an issue in Alberta, BUT ozone levels do build up on the eastside of Edmonton and as far as Fort Saskatchewan on hot summer days – 1 or 2 blips a year above the current Canadian standard, but under U.S. standards. Ozone is largely NOX and volatile organic compounds based and urban haze adds SO2 dust and many other materials. Discussions with people involved with CASA related activities note serious concerns about future ozone and emissions in general in the Fort Saskatchewan (AIH) area. [24] Very appreciable attention is starting to be focussed on existing and future industrial development.
Ozone is a specific concern A recent Chemical and Engineering News article “Texas Commission Reconsiders NOX” in the suggested complex discusses major air quality control challenges in the Houston area. The eight county area site area, but virtually all has severe warm weather ozone problems and industry will be paying $1 to $1.4 billion to emissions will be analyzed reduce NOX and VOC’s – “ethylene, propylene, butadiene, isoprene, formaldehyde” and other materials…“from cooling tower, flares, leaky components and vent gases”. The very closely. The Texas particular area of Texas has an ethylene production capacity of roughly 13,700-KTA of situation noted in the side ethylene about 46% of U.S. ethylene production. The study team would be surprised if the bar is expected to repeat in Houston area situation was not brought up by environmentalists relative to any major new the AIH. petrochemical project northeast of Edmonton.
Table 5.2-1. Principal Air Quality Issues Today Oil Sands Fort Saskatchewan / Note Redwater Cumulative Emissions (all) High! Growing! Environmentalists and citizens major concern – catch all. Smog / Urban Haze NOX / VOC / Dust Local (a) Significant Visual public perception with asthma et al impacts on sensitive individuals. Ozone Minor High-Growing Expect Extreme Pressure Particulates NOX / SO2 / Dust Local (a) Growing! Non-visual particulates of major health concern. Acid Precipitation (Dry & Wet) Major! Minor Sensitive soils to east may be approaching limit. Principal Facility Component Sources SOX Upgraders Oil Field (small) / Upgrader May be peak northeast of Fort (small plants, small Saskatchewan * flexicoker, boiler Coal Power (west) stacks NOX Diesel Engines High Temp. Furnaces (c) * FCC Stack Cogeneration Cogeneration VOC’s Process Units Process Units Odours * Mine Faces (Fugitive) (and Fugitive HC’s) Waste Ponds Dust Mining Haze from Edmonton Odours (a) In region of plants – in river valley and to east. (b) SO2 / SO3 also contributes to smog. (c) Cracker Furnaces. * Expect major Fort Saskatchewan area pressures.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 55 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 5.2-2. Air Quality Control in Proposed Core Facilities (a)
Plant Areas Emissions Cracking Gas Turbine FCCU Sulphur Plant Process in Storage Furnaces General
NOX Low NOX New Low NOX May need DeNOX -- Low NOX -- Burners (may Large Frame System Burners * have to go Gas Turbines further) (<9-ppm) *
SO2 -- Only Sweet Common 99.9% Efficient Flue Gas -- -- Fuels Desulphurization
VOC’s ------Extreme H2S etc. Major Leak Detection and Repair Controls above Program. molten sulphur Special covers on wastewater and Sulphur Degassing similar systems. Special Tank Blanketing Particulates -- -- FGD System will ------pick up 99% of fine catalyst emissions Toxic Emissions ------Very special attention in design. * No synthesis gas use.
The proposed new SGL capture facilities in the oil sand area will reduce some flaring and combustion of some sulphur materials (and related odours), but there will be some added NOX from added cogeneration (gas-fired).
Regardless of how benign the new units, air issues will be highlighted in the regulatory processes – including local development permitting. The fact that this area is downwind of the coal-fired power plants and Edmonton with a very (in?) convenient river valley duct makes the situation more difficult. The current Texas studies and industry and regulator responses must be deeply explored for clues here. We anticipate sulphur capture levels at 99.9% to be mandated, hence, a very high performance – e.g., ammonia-based flue gas scrubbing system (s) will be needed on sulphur plant and very probably FCCU stacks. (Marsulex advise such a recovery can be obtained in ammonia scrubbing such as going in at Syncrude’s new fluid coker.) [25] 1,000+tonnes per day of sulphur is a major quantity and very excellent degassing will be essential, regardless of its destination – proposed local in pit storage may be an odour challenge itself.
The presence of butadiene and naphthalene are two examples of toxic compounds permitted only below 1-ppm in ambient air. This indicates needs to insure all operations, especially specialty chemical related ones, have very stringent air quality controls. Note that all aromatic product tanks will have nitrogen blanketing with special treatment of all releases to atmosphere.
5.3 Water
Air-cooling is strongly recommended throughout the new facilities – with very special attention to sound control- to minimize cooling water use and related losses.
Water withdrawal permits may be difficult to get in the Fort Saskatchewan area, although at least Dow, Shell and Atco have intake systems to be considered on the east side and Agrium on the west. A large pond may/will be needed to cover water makeup during low water periods. Dow has set a precedent through near zero water discharge from their newest units – we see the same very stringent control here. There will be appreciable wastewater to be treated and recycled to the maximum extent, especially from the Petro FCCU and, more particularly, gasification.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 56 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Serious consideration must be given conversion of excess hydrogen to hydrocarbons in; say Fischer Tropsch synthesis (with CO) routes to recover as much water as possible of that fed to gasification.
3n H2 + nCO Æ H2O + (CH2) n
Recovery of water from gasifier ash also will require special attention. Water control in the C2 C3 cracker will follow proven practices at existing Alberta plants. Salt cavern development will be a major water user. (Brine disposition existing systems should be available.)
Water will be a major issue, with federal, provincial, and local government agencies and NGO’s all deeply involved.
5.4 Land
The gasifier ash will require secure landfill until there is a regional spent upgrading catalyst processing plant recovering vanadium and nickel values.
Sulphur disposal may be to special pits, such as Hazco is proposing for the Albian upgrader’s product. Salt cavern sulphur should be considered as an alternate to the Hazco proposals
The Petro FCC will have 1 to 2 tonnes a day of spent catalyst fines. This may not be hazardous due to metal contents, but its disposal also may require secure landfill. (This will likely be a unique catalyst without significant resale potential unlike a similar catalyst from one downtown refinery.)
The zero water discharge target will generate significant solid wastes for disposal, but Dow’s experiences in this area will hopefully be of great help.
5.5 Greenhouse Gas Issues
5.5.1 Introduction
Greenhouse Gas Emission Reduction Controls –“voluntary” and/or regulatory – are coming! The U.S. in total, ironically, is actually leading the way in North America but our oil and gas businesses are doing a good job. However, much more will need to be done. The Alberta government is proposing a 50% reduction in the average greenhouse gas intensity of industrial products. This concept has yet to be defined in any detail generally and for any individual industrial sector but provides a guide for consideration. Alberta Environment has effectively capped electricity generation kilograms of CO2 per kilowatt hour at natural gas combined cycle levels by ordering new coal fired plants to buy offsets down to that level.
Figure 5.5.1-1 summarizes a recent set of crude oil life cycles prepared for the Regional Issues Working Group. These are based on crude / SCO refining in Chicago markets, but still directionally applicable for the Alberta scene.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 57 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
FigureFigure 5.5.1-1. 1.1. 2007 Greenhouse Gas Life Cycles Estim ates 4500 4000
3500
3000
2500 2000 E 1000 litre Transport Fuel Transport E 1000 litre 2 1500
kg CO 1000
500
0 Canadian Light Brent Arab Nigerian Mexican* Canadian S.C.O. Canadian V enezuelan Blend Light Ex c rav os * Blend Diluted Partial Upgrader* Transport Fuels Combustion Byproduct Combustion** Refining Transportation Production
* Non- Kyoto Agreement Country. ** Includes upgrader coke product use by others, w here applicable.
Little has really been done anywhere on the end user end, which really determines overall emissions, but California has started towards new reduced emission vehicle standards New York and various and New England states are advancing on several producer fronts.
Demand for refined petroleum products in a Kyoto constrained world may impact on incremental bitumen and SCO production but its much too early to guess at the consumer end. This study assumed only current levels of gasoline, jet fuel and diesel demands, despite increased economic activity and population.
5.5.2 Site Emissions
In the new complex much of the GHG emissions will come from the following sources with very rough estimates for CO2 per day noted:
a. Gasification CO2 if not recovered - 21,000 tonnes per day (no Fischer Tropsch) b. Petro FCC - 3,000 c. C2C3 Cracker - 6,000 ?? d. Other Process Furnaces - 1,000 ?? e. Utility systems – cogen, boilers, etc. - 2,000 ?? TOTAL - 33,000 + 20% tonnes per day
All but 1 or 2% of this CO2 equivalent will be CO2 but possible N2O emissions from the Petro FCC stack and perhaps gas turbines may need attention. Assuming that the feeds total at about 220,000-BPD,
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 58 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 emissions are in the order of 150-kilograms of CO2 per barrel (totally arbitrary base). With Fischer Tropsch, the total drops to roughly 24,000-tonnes per day – 110-kilograms per barrel.
Routing of excess gasification CO2 to CO2 EOR and/or offsite disposal would reduce the unit rate to the order of 55-kilograms per barrel (100 if only bitumen feed is considered), and this is for upgrading, refining and petrochemical operations. This appears a reasonable level as Syncrude and Suncor are expected in the near term to average in the order of 90 to 100-kilograms per barrel of SCO, and further refining of SCO results in roughly 30-kilograms of CO2 per barrel. For reference Albian and Fort Hills project 35 to 40-kilograms of CO2 per barrel of partially deasphalted bitumen; that is the low-end of SAGD range, but with low pressure SAGD, possibly reasonable by 2010. If the C2 C3 cracker is not considered and if gasification CO2 can be routed to CO2 EOR or other disposal options, the suggested complex would appear to be at below 50% under current Alberta CO2 per unit of industrial product.
5.5.3 Project Offsets
While there are significant GHG reductions in the SGL source plants, this is partly offset by the electricity required in cryogenic SGL recovery. However, a credit of at least 2,000-tonnes per day would appear attributable at Syncrude and Suncor to SGL recovery.10 At Joffre there would be credit due NovaChem for their hydrogen and related compression – say 800-tonnes per day, resulting in an overall external credit of about 1,000-tonnes per day – another 4 (8) kilograms per barrel of total (bitumen) feed credit for the new complex.
D. Stephenson’s very extensive work on CO2 EOR and on collection / distribution / CO2 EOR / related uses is available in a purchasable report and has been summarized in two recent papers. [14] Discussion with Mr. Stephenson indicated a likely peak in CO2 EOR light / medium crude production of 100,000-BPD, which corresponds to roughly 26,000-tonnes per day of sequestered CO2. In practice, there will be a need for some other disposal options. But there are a number of other available low-cost CO2 sources – e.g., hydrogen units and ammonia units – with their own CO2 EOR outlet.
The 21,000-tonnes per day maximum emission level (of gasification CO2 – the only concentrated CO2 available) is frankly too high for crediting it all to CO2 EOR new oil, but with Fischer Tropsch use of 40% or so of that CO2 it may be possible to reach a 35,000 barrel of new oil credit.
5.5.4 More Work Needed!
Much further work will be essential relative to CO2 emissions – they will be on the same major agenda as other emissions in scrutiny of any/all proposed Redwater / Fort Saskatchewan area industrial development. At this time, there appears to be a good story to tell IF the requisite CO2 to EOR system becomes reality.
5.5.5 CO2 Disposal Note
Note that Alberta aquifer and, depleted gas fields and depleted oilfields offer potential to sequester much more CO2 than does CO2 EOR and, hence, CO2 production is not itself an issue, but the issue is the cost of its disposal. CO2 to CO2 EOR should be at least cost neutral at the production site, but disposal options all add $10.00 to $25.00 a tonne costs. [14] There appear to be suitable aquifers in the Lake Wabamun area and even the next door depleted Redwater oilfield may offer CO2 sequestering potential albeit at low pressure (well below the critical). Obviously, it will be essential that several disposal sites are attached to a major CO2 to CO2 EOR grid to provide outlets when CO2 EOR cannot take all available CO2.
10 Interestingly, if all SCO hydrotreating were to be done at this site and the equivalent CO2 routed to CO2 EOR rather than partly to Fischer Tropsch liquids, Syncrude and Suncor would be reducing their CO2 emissions by roughly 10,000-tonnes per day – about the same amount with Fischer Tropsch production from the same hydrogen (and CO) at the new complex site.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 59 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
A major CO2 use / disposal grid is a must!
5.6 Preliminary Economic Review
The overall key product yields estimates for the key process alternates considered in the fiscal year are shown in Table 5.6-1.
• Hydrogen and CO2 are high without Fischer Tropsch conversion. • Targets for ethylene, propylene, benzene and p-xylene production are met in all cases, except a slight shortfall in benzene when purchased vacuum gas oil is excluded.
• The added C3 cracking case represents at or near maximum, as the C2 C3 C4 cracker would then be at 1200-KTA world scale. • Naphtha and jet / diesel markets appear available (noting 7,900-BPCD of Fischer Tropsch naphtha priced at $30.00 per barrel for out-of-province ethylene production). • Alkylate markets appear available in all cases – directly or in an onsite gasoline blend.
Fischer Tropsch liquids from synthesis gas was considered preferable to the high CO2 and hydrogen rates and also recaptures much of the water used in gasification, hence, the Reference Case’s A + B + C + D (Fischer Tropsch).
Table 5.6-1. Overall Yields of Key Products CASES Product Basic Reference Reference Reference
(Basic & Fischer Tropsch) Less HGO Plus NGL C3 Ethylene 1110 1110 1010 1510 Propylene 1430 1430 1100 1560 Benzene 510 510 430 540 P-xylene 720 * 720 * 530 * 720 *
Hydrogen (630) (40) (50) (50)
C4 Alkylate [38,800] [38,800] [28,100] [40,300] Naphthas [17,500] [25,400] [20,700] [25,400] Jet / Diesel [28,600] [45,100] [45,100] [45,100]
CO2 <21,000> <12,000> <12,000> <12,000> Sulphur <1,160> <1,160> <970> <1,160> * Part or all can be converted to benzene at 70% weight yield.
In order to provide clues as to appropriate futures thinking, a series of simple economical cases were run to test the influence of key variables and options in the basic scheme. No detailed step by step and/or year by year analyses was made – but overall A + B + C capital was assumed spread over two years.
The fiscal bases assumed were 29% capital cost allowance, 29% (as anticipated in 2007 rate), Canadian dollar at $0.65 to U.S. The basic petrochemical products were priced at USGC May / June 2002 contract prices less $0.02 to $0.03 for freight and some marketing allowance – a level allowing a new Alberta producer to ship monomer to the USGC.
A 25-year operating life was assumed as a base; with a discount factor of 8% was used. However, again it must be emphasized that the economic tests were very largely to indicate if the basic Steps A + B + C scheme made sense and what would be logical add-ons.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 60 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 5.6-2. Very Preliminary – Internal Rates of Return and Net Present Values (2002 dollars / no inflation) • With Petrochemical Monomers $0.03 U.S. under USGC unless noted • 29% (2007) Tax Rate unless noted • 25-year Operating Period • 29% Capital Cost Allowance • 8% Discount • 1% per year Sustainable Capital Fischer Tropsch Value Check IRR% NPV 106 Note I Base A + B + C without Fischer Tropsch 15.2 5,443 II Base A + B + C with Fischer Tropsch 14.9 5,389 BASE CASE ALL OTHER CASES HAVE FISCHER TROPSCH Fiscal Checks III Current Tax Rate 14.0 4386 IV More Capital 10.7 2,449 +25% Product Pricing Checks V Petrochemicals Reduced $0.03 per U.S. 11.9 2.941 VI Petrochemicals Increased $0.05 per U.S. 18.2 8,292 Feedstock Changes VII Reduced HGO purchase by 30,000-BPD 12.9 3,447
VIII Added NGL C3 to bring gas cracker to world 14.7 5,592 scale. IX VIII but with $18.00 per barrel NGL’s 15.1 3951
As Table 5.6-3 illustrates, overall capital costs were estimated at $8.7 billion in total unescalated 2002 Canadian dollars. This estimate is very preliminary, but does include $0.4 billion for current Williams Energy SGL related facilities. Step costs were estimated at $3.1 billion for Step A, $2.0 billion for Step B and $3.6 billion for C/D, both A and B steps include significant pre-investment for subsequent stages of development. Thus, all economic calculations were based on the overall project – assuming construction costs spread over two years.
The capital estimates are preliminary and there is some anticipation of progress in lowering capital and operating costs in many cases. The basic process schemes will be finalized approximately 2-1/2 years prior to startup, hence, with the assumed staging there will be 2 to 5 years of further process and related catalysis development before the finalizing of process configuration and major equipment sizing. While that finalizing will be based on the most appropriate catalyst of the day and process to feed and product matching, catalyst development and trials will continue up to about 1-1/2 years before startup with the initial catalyst charges being the “best” proven and available ones at that time.
• If Fischer Tropsch synthesis made sense with high YES pitch gasification rates? (due to Environment)
• If there is value in purchased raw heavy gas oils YES (at $25.00 per barrel)?
• If increasing the C2 C3 C4 cracker to world scale MAYBE makes sense? (depends on feedstock cost and on product demands)
The latter option could be added at any time via new furnaces, but some over sizing of recovery equipment would be appropriate if likely near-term need. The cost and yield data were developed for process / process research-planning purposes and must be considered only in that context. These economics are only for illustration! Much more detail is needed in all cases.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 61 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
Table. 5.6-3. Capital Estimate - VERY PRELIMINARY - (in millions of 2002 Cdn $)
Total C + D AB A + B + C + Fischer Tropsch Fischer Tropsch
Off Plot Williams Energy 400 - - 400 Syncrude 330 - - 330 Suncor 150 - - 150
Refy C3C4 Spl. 20 - - 20 Misc. NovaChem / Dow 20 30 - 20 TOTAL 920 30 0 950 On Sites
SGL Frac / C3=Splitter #2 150 100 50 300
C2C3C4+Cracker 1300 30 30 1360
C4 Complex 250 100 60 410 TOTAL 1700 230 140 2070
HGOHT - 200 10 210 Petro FCCU - 360 150 510 Sulphur 20 100 100 220 Aromatic Complex - 600 100 700 TOTAL 20 1260 360 1640
Crude/Prim. - - 400 400 NHT - - 30 30 J/DHT - - 150 150 #2 HGOHT - - 200 200 Gasification - - 1550 1150 Fischer Tropsch - - - 400 TOTAL 0 0 2330 2330 Off Sites Inter casements 150 120 180 450 Tankage/shipping 50 100 100 250 Utilities 100 100 250 450 Misc. 50 50 50 150 TOTAL 350 370 580 1300 Project Owner Costs 100 70 70 140 Temp. Facil. 60 30 30 120 Misc. 50 50 50 150 TOTAL 210 150 150 510 OVERALL TOTAL 3200 2040 3560 8800
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 62 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 6.0 OTHER PROCESSING OPTIONS
6.1 Introduction
This section discussing a wide variety of options considered, but not used in the final A + B + C scheme. However, most of these alternates need study in future related development.
Fuel Gas
Ethane Existing Ethylene Units
New C2 C3 Cracker *
Propane Markets
C2 C3 Cracker * Optional
NGL C3
Propylene Aromatics Ethylene Propylene + Metathesis Disproportionation Butylene Petro FCC Reaction *
Onsite Bitumen Diluent * Naphthas Offsite Ethylene
C3 to C2 C3 Cracker iC4 to Alkylation
C3 C4 Segregate
C6+ with
Refinery C3 C4 Naphthas & Aromatics ν Aromatics or Pentanes Plus Reform Aromatics ν C5 to C8
Flexible Feed Cracker Current Off Plot
NEW * (Future Option)
Existing Coker C4’s Alkylation *
C4 Naphthas Naphthas Hydrotreat *
All New Virgin Jet / Diesel Hydrotreat * RPP’s (SCO Blends) Coker Distillates Heavy Gas Oil Hydrotreat
* In Core Complex. ν May be in refinery. Basic Assumption Planned not modelled
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 63 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 6.2 Other Processing Options
1. Flexicracker versus A + B + C
This study started from consideration of a flexible feed ethylene unit.
Hydrotreated HGO Optional C3 C4 Naphtha Light Gas Oil
1,000-KTA Maximum of Ethylene
But the basic A + B + C scheme replaced that here with: HGO’s SGL et al
C NGL C3 2 C3 Hydrotreat
Possible Petro FCC C3 C4 Increment 1,200-KTA Maximum (world scale) 200-KTA of Ethylene (Mostly Propylene & Aromatics) Ethylene 800-KTA
With another 100 or so KTA recovered from SGL’s. The Petro FCC enhances the propylene and aromatic yields with ethylene almost as a byproduct.
All available jet and diesel boiling materials were assumed to find good homes in regional and West Coast fuel markets (along with C4 alkylate never considered for cracking due to entirely isoparaffinic nature). However, the qualities of the middle distillate blends would possibly qualify them for furnace cracking if prices cratered.
2. Naphtha Conversion Options
Cracking The naphtha pricing assumed in this study generally ruled out its use in a new, more expensive (20% more per unit of ethylene) flexible feed cracker. (The Fischer Tropsch naphtha stream would probably go to offsite cracking at a discount to diluent use.)
LPG’s from Naphthas for Ethylene and C4 Alkylate C2 C3 C4 cracker provides some options to indirectly crack naphthas following conversion to propane (and isobutane, which would go to alkylation).
i) Naphthalene containing Naphthas – e.g., bitumen conversion, refinery naphthas, C5+ C6 to C8’s. Mono metallic (platinum on silica) catalytic reforming is used to convert such naphthas to propane, butanes, and an aromatic concentrate in a (few) simple units. In effect, the hydrogen from naphthalene conversion to aromatics is used to hydrocrack C6 plus paraffins to C3 and C4. There are not many such units using what was once the standard reforming catalyst. ii) Paraffinic Naphthas – e.g., raffinate from aromatic recovery, pentanes plus from SGL Fractions. Fischer Tropsch naphtha. These can be easily hydrocracked to propane and butane, using extraneous hydrogen. iii) Raw Product Hydrocracking – The whole C5 plus stream can be hydrocracked to propane and butane if desired (after light olefin recovery).
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 64 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 iv) Aromatic-Rich Streams “Purification” – e.g., the aromatic concentrate from option i) and any other stream with reasonable – say 60% - aromatic content. Zeolyst has a new proven11 catalyst to hydrocrack the non-aromatics to propane and butane, allowing bypass of the standard BT extraction system. This appears especially attractive for the aromatics complex considered here, as its raffinate could well prove difficult to market. (There is one Edmonton benzene-rich stream processed at another refinery for its benzene that would be ideal for this process, at the same time unloading benzene extraction at the present site.)
Note that propane would go to C2 C3 cracker and iC4 to alkylation.
3. Naphthas for Aromatics
The earlier aromatic study indicated a need for a new high severity catalytic reformer in one Edmonton refinery to produce almost enough BTX to provide feed to a new styrene plant. The study believes that potential still exists – partly due to the onsite need for its added 30+ 106-SCFD of hydrogen. In this case, the catalytic reformer could be at the refinery or in the new complex. In addition to the refinery C6+ naphtha, the bitumen conversion, naphtha would also be converted. This option warrants very serious study due to the ability to add in the order of 500 to 700-KTA of benzene and p-xylene to the complex’s output.
4. Propane to Propylene
As noted above, both conversions to propylene and conversion to aromatic routes were modelled, but not used in the basic scheme. [26] [27] The first is the default case if more propylene is needed; naphtha reforming appears best for more aromatics.
One very simple opening route would be to:
• Capture SGL’s and bring in petrochemical C3 C4’s and excess refinery C3’s. • Fractionate ethylene product. Æ Ethane to existing crackers (to about 10% of nameplate, considered doable with low capital). • Fractionate propylene from SGL’s and other feeds. • Dehydrogenate propane. • @ 80+ weight yield to propylene and significant 5 to 6 wt.% hydrogen. • This process is becoming well proven being used at the primary propylene. The process is essentially the same as used to dehydrogenate isobutane at Alberta EnviroFuels – slightly higher severity.
• Convert C4 olefins to C4 alkylate.
The capital cost of such a route would be roughly $400 million less than one containing a new C2 C3 = cracker. The new ethylene yield would on be in the order of 500-KTA with propylene near 1000, using only SGL propane.
11 SK Korean development and prototype operation. [22] [23]
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 65 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 5. Propane to Aromatics
The Cyclar process was also modelled but not considered in the basic scheme. [26] [27] The weight yield is only 60+wt.% to BTX, but with high benzene content; 30+wt.% of methane (?) is a major challenge H2 is in the 5% range. The one unit started up a number of years ago was shutdown due to mechanical troubles, continued shutdown for several years due to low p- xylene market prices and at time of writing, a crew were restarting. [28] This process fits well with the suggested aromatics complex as the latter would handle the reactor’s liquid product.
6. Light Olefin
The olefins in the C5 portion of various naphtha streams – e.g., Petro FCC, ethylene plant byproduct (after diene removal or partial saturation, SGL C5’s, probably including raw Fischer Tropsch naphtha can be converted to propylene (40-45%) butylene (30%), ethylene (10%) at, say, 85% conversion if ongoing Lurgi and SudChemic propylene demonstration plant operations process successful. [29] The non-olefinic streams pass through unreacted and could form a portion of the naphthas led to the Petro FCC, which in turn will provide more propylene, butylenes and pentenes. [30]
The incremental ethylene and propylene would go directly to final product “finishing” and the butylenes to C4 alkylation, recycle to the propylene process or to metathesis with ethylene to produce more propylene.
This study did not attempt to integrate options to convert internal naphtha to other higher value products. However, there is a very wide range of options – the above should only be considered as examples of many to be explored in further studies.
7. SCO C4’s and Naphthas
The SGL capture schemes collect only C4’s surplus to SCO blend needs, i.e., material in fuel gas. Roughly 25,000-BPD of C4’s would be going into the 700,000-BPD of coker-based SCO assumed as the bases for SGL rates to Step A. Roughly half these “butanes” were originally butenes with some butadiene. They consumed significant hydrogen – 15 to 20 x 106-SCFD as they were hydrogenated with other naphtha components.
Do all C4+ These C4s would be expensive to distill out at the upgraders and such naphtha an operation would necessitate changes to one or more hydrotreating hydrogenation units. However, a new SGL line is a necessity with full SGL recovery in the south and whole C4 plus naphtha streams could easy be shipped south in such a time for C4 capture and C5 plus hydrogenation. The C4 olefins go to more alkylate, being replaced with SCO with low-cost NGL butanes in the final SCO’s.
8. All New Hydrotreating in South
Carrying the above idea a step further, all new virgin and cracked distillates could be hydrogenated in the south probably in units separated from those of Step C, but with common sulphur recovery, utilities services and many southern site amenities. Capital costs would be much reduced in the north, overall due to no need for hydrogen and lower capital (25+%) in the south before synergy credits.
Steps A + B + C (but no Fischer Tropsch) facilities will have enough hydrogen for 500,000+BPD of upgrader distillates.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 66 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 If the hydrotreating were done in the south 10,000 or so tonnes per day of CO2 would be transferred too – reducing at site GHG per barrel by a very significant 15 to 25%.
9. Other Hydrogen Related Items
This study indicates that hydrogen will continue to be the major vector to convert bitumen to chemicals, as well as refinery feeds.
i) Hydrogen Grid – A major Edmonton / Fort Saskatchewan grid interlinked with the suggested new Joffre supply appears essential to optimize existing and new hydrogen production and demands – including fuel cell vehicles in time. There are still untapped hydrogen sources – e.g., at two chlorate plants. ii) Hydrogen Recovery – with SGL Capture Recovery of hydrogen in conjunction with SGL’s with improve SGL capture economics and reduce oil sand plant greenhouse gas emissions and natural gas purchases. (This study did not attempt to optimize hydrogen recovery from the off-gasses from the many hydrotreaters and minor hydrogen-rich streams.) (The Syncrude provided data listed a number of hydrogen- rich fuel gas streams not considered in this study due to low C2 plus potential and that all paraffins.) iii) Hydrogen to onsite Fuel Cell Electricity and Heat Generation – when such becomes economic. One early 1990’s Alberta study in the ADOE’s Hydrogen Research program noted that fuel cells have some potential to remove hydrogen – to energy – from hydrogen-rich streams.
10. Added Conversion in South
Fischer Tropsch Specialties Note
The world is awash with Fischer Tropsch microcrystalline waxes, but until recently Alberta, polyethylene producers were importing C6 and C8 alpha olefins from Sasol in South Africa – Fischer Tropsch derived. Premium lubricating oils can be produced from Fischer Tropsch products. It is possibly best to start thinking from synthesis gas, CO and hydrogen, as it is the starting point for Fischer Tropsch, for methanol (with its new petrochemical monomer production processes), dimethylether, and a very wide variety of smaller scale petrochemical derivatives.
An Air Products Houston pilot plant had proved up fluid bed process for methanol and were close to doing the same for DME at time of contract, and has also been used by one or two other process developers for Fischer Tropsch catalyst studies (successfully, to our limited knowledge). This illustrates part of a spectrum of synthesis gas derivative options. Higher alcohols are, for example, a possible – well-researched – further options building from methanol technologies.
Changing the Fischer Tropsch catalyst and reaction condition can be altered to produce lighter olefins (usually with much added methane production). A very broad spectrum of product options is available. In Malaysia Shell make much of their money from their based Bintula project from x-olefins and other specialties, for example.
It is to be noted that GTL gas to liquids technologies are being translated into major new Qatar and Nigerian naphtha plus jet plus diesel ventures and Sasol is adding major natural gas-based synthesis gas production to its Fischer Tropsch et al operations, possibly, backing out some coal gasification. Studies and pilot work were underway at time of writing re converting Alaskan gas to Fischer Tropsch liquids for use in west coast and/or for east markets.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 67 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
Conversion would be limited by CO2 constraints other than as new basic Step C and new primary bitumen conversion routes produce a lower percentage of pitch to be gasified.
11. Specialty Intermediates and Derivatives – A Major Area of Economic Potential
There are many more options to be considered, the above must be considered, only a starter list to be added to! This study only developed a basic scheme that appears reasonable on which to start development planning and R&D&D needs thinking.
The study does note major potential to further integrate upgrading, refining, petrochemical derivatives and new units in the core complex. There will be new SGL’s other C2 to C4’s, and many other new streams to be processed in the complex and associated units – all around the utility / service core.
The R&D&D further extends the potentials for economic enhancement of Alberta’s bitumen to chemical industry.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 68 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 7.0 POSSIBLE DEVELOPMENT PROFILES
7.1 Introduction
The original terms of reference (Appendix A) noted 2007 and 2015 as the key reference years. Forecasting of product demands, economics and technologies is problematical and only directional at best. Here, the one sure thing is the availability of the world’s largest bitumen reserves – resource supply is constrained only by markets, economics, and possibly environmental issues such as some form of Kyoto agreement. Corporate structuring, financing, ownership and operator ship of the relevant facilities has not been considered, but obviously will be major factors in what actually evolves.
Technologies expected to be proven in full relevant commercial use four years prior to individual startup data are assumed. Most “new” processes assumed are step-outs of current technologies and catalysts. Certain new technologies that may provide breakthroughs and current technologies requiring ongoing development are discussed in Section 8 below.
Expansion of existing ethylene plants via addition of SGL ethane up to 10% existing capacity is assumed possible at minimal cost, with possibility of routing a concentrate of the small SGL ethylene to the recovery system of one, again at minimal incremental cost. However, in such a case, Steps B and C and D are not foreseen, as new propylene would have to be via propane dehydrogenation.
Thus, this study has assumed new facilities for propane and heavier cracking with all new ethane cracked in the existing units in addition to NGL ethane. This study did not consider the potential to revise / expand existing ethylene units for propane due to likely significant costs (including loss of production) and the complexity of analysis and confidentiality of most key basic information. In practice, propane cracking would be considered both via additions to existing ethylene units using ethane additional loads via a new cracker (integrated to other new units) using NGL propane (expansion for naphtha and perhaps gas oil now appear unlikely in such a unit). Cracking of some normal butane would also be considered, especially, as its cost can be lower than propane during certain seasons of the year and it would be available from the new C4 complex.
The Williams Energy polygrade propylene system has been assumed as integral, operationally at least in the early stages of petrochemical monomer expansion with a new parallel system would be appropriate. Perhaps only chemical grade propylene would be economic for certain new users.
While the study tended to focus on near-term 2007 / 2008 and long-term 2013 / 2015 periods. It is noted that a new complex and projects can/should be/will very likely be built up in stages. Some individual projects and groups of projects maybe proceed much earlier than others do.
Emphasis has been placed on new integrated facilities in the Fort Saskatchewan / Redwater area. Integration with existing local plants and prospective new petrochemical derivative users in the same area is assumed to a maximum extent. Pipeline integration is assumed with oil sands areas, Edmonton, Joffre and the Vancouver area (as discussed later under infrastructure) – pipelines coming available when needed – see Figures 7.1-1 and 7.1-2.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 69 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Figure 7.1-1. New Coking SGL Line BPD Upgraders SGL 60,000 Raw Naphthas <125,000 MAJOR CO2 DISTRIBUTION GRID CO2 Arctic NGLs ? 30 to 80,000 (?)
CORE A ++B C Δ Naphtha HT
NGL’s NEW LIQUID LINE Consider C4 Alkylate 25,000 + Fuel Rate TRANSMOUNTAIN Naphtha 25,000 + Jet/Diesel 50,000 + to New Clean Products Line Enbridge
Figure 7.1-2. New Links to be Promoted Arctic NGL Capture SGL Capture Gas/Liquids ? Integral with Project Bitumen Oil Sands Various O New SGL Plus Line Hot Link (already in planning) (P) or CO2 Grid Use existing dilbit/diluent systems CO EOR rs 2 R G onome To New Petro- etc. (P) PC M C 3= chemical Industry Xylenes Dow Refineries C 3, C4, etc. Byproducts Upgrader HGO’s CORE RPP’s C 5+ A
H 2 RPP’s A/S A CO2 Naphthas C + tain 3 Enbridge Systems oun nly * H2 (P) sM A O ran e C 4 CO T elin e/S Pip rud NovaChem g C Vancouver stin Exi Joffre Anacortes, etc. Legend: O - Current mined oil Sands area A - Redwater/Ft. Saskatchewan Area A/S - Strathcona / Edmonton Area J - Joffre Special: R - Bridge over North Saskatchewan at Redwater (Road/Rail/Pipeline) P - Formal Pipeline G - Local product/feed grids. Existing or Already Planned Notes: Assumes S/D of Prince George and Burnaby refineries will use RPP’s from core complex. * - May carry CO2 - if not add CO2 pipeline.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 70 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Added bitumen and/or derivative processing at the new complex must also be factored into planning.
New related facilities in oil sand areas have been assumed as the minimum required in order build the core complex and to keep capital and operating costs down. However, this does not preclude partial upgrading in the field – e.g., partial deasphalting of mined bitumens and/or partial upgrading (and related pipeline) consistent with the core facility (virtual” upgrading) with hydrogenation in the new core.
Pipeline and other integrative features have been assumed available as needed (with appropriate all in tariffs per unit of throughput).
7.2 Siting and Access
7.2.1 General
The overall new core facility site should be large enough for A + B + C + D and specialties and for a series of new derivative producers. The utility and service functions would be largely common serving the entire site. At this time at least one section of land appears essential. Closeness to existing industries, rail lines, roads and pipelines will be virtually essential to maximize synergies and lower costs. Access to and/or use of current water intakes, brine ponds and brine disposal wells would be very welcome and further enhance integration.
Early identification of a section or more of land for the proposed complex is strongly recommended. This study did not do more than to ascertain that there were at least four good looking prospects of at least one section – one between Shell and Dow plant sites owned by the County of Strathcona. Other possibilities exist north of Williams Energy in Sturgeon County, east of Bruderheim in Lamont Country (Encana ownership), and another northeast of Shell, in the region envisaged as best suited for the new complex.
It is recommended that very early in overall program development that one of such sites be brought under some form of option, with at least control over all new plants in the near-term to insure compatibility and maximize synergy as the complex evolves. Location can be very important in attracting partners and in defining product options.
7.2.2 Corridors
The region is currently developing service corridor plans, but these will need much definition relative to the specific site. However, of equal importance to internal regional planning are the needs for defined corridors for pipelines from the north, to/from Edmonton, Joffre to Edmonton and probably other routes for the pipelines foreseen. In/out points around Edmonton are particularly important. New crossings of the river must also be considered.
This appears primarily a provincial responsibility and an urgent need.
A new bridge across the North Saskatchewan River is an urgent need – it should have rail to improve service on both sides of the river as well as pipeline carrying components in addition to highways for emergency, as well as industry needs.
7.3 Specialty Products Notes
While the study notes possible opportunities for many specialty products the base case assumes none – here all smaller-scale byproducts are processed in some way to one or more of the above products. Specialty product options are discussed briefly.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 71 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 7.4 Arctic Gas and More NGL’s
While this study did not consider Alaskan and/or Mackenzie Delta gas and related NGL’s in any depth, they must always be in mind as organizing / planning / production / new monomer marketing proceeds. Williams Energy recently noted potential for 80,000-BPD of Alaskan ethane and 20,000 of Delta ethane.
Alaskan ethane may become available. Routing of Alaskan north slope gas to the U.S. West Coast as LNG appears as logical and possibly more economic than an overland route. Phillips already has a LNG plant on the Alaskan south coast – supplying Tokyo Electric from very dry Cook Inlet gas and a recent Oil & Gas Journal paper discussed processing North slope gas as LNG plant feed, noting two southern Alaskan LNG plant siting options. [30]
A recent Regional Issues Working Group (RIWG) forecast of natural gas needs for surface mining and SAGD bitumen current and projected (on a discounted basis) operations indicated one BCFD of gas needed in the 2005 era, rising to two by 2010. [31] The latter figure “feels” high, especially if new hydrotreating in upgrading were to be done in the south after, say, 2007 as recommended in this study, and as cogeneration is reduced only to satisfy onsite needs, line capacity not now being available for major added electricity movement south to the supply short Calgary region. Line losses, without, say, DC or perhaps ultra-high voltages would be over 15% for such movement in conventional systems. Also, cogenerated electricity does not provide peaking demand needs; hence, competes with low-cost coal- fired generation. From a greenhouse gas standpoint, generation in oil sands areas for sale in southern Alberta (and/or U.S.) is less efficient than minimal generation only for onsite needs and modern high efficiency combined cycle generation, with peaking capabilities (which may be only single cycle).
Reducing thermal needs over time as SAGD type operations improve – e.g., low-pressure SAGD – will slow the buildup in oil sands gas demands.
However, even at one BCFD, which is slightly under current Delta gas rate projections, it is very important to take full advantage of Delta gas as directly as possible to the oil sands area at the lowest cost. Natural gas replacement for SGL’s is, next to bitumen, the most expensive “feedstock” to the overall developments discussed here. Even a $0.25 Canadian per GJ reduction in gas cost represents a gain of 0.3% in return on overall investment.
The Delta NGL’s picture was very unclear at time of writing, with Imperial and Shell gases being very dry and Phillips / Conoco’s very wet. The Tuk area gas developments are very likely to lead to further very wet gases. The Enbridge line from Norman Wells can only take C3 plus liquids, although on C4 plus extraction, was apparently being considered by the Imperial / Shell group at time of writing.
Even assuming the (very?) low 20,000-BPD of ethane estimate of Williams Energy it would be highly desirable to extract that ethane and residual propanes from the Delta gas in the oil sands area and convey the recovered C2 plus in the SGL stream. [32] The added ethane to the new complex could contribute at least 350-KTA more ethylene. This is roughly the extension considered above to the basic “A” case C2 C3 (C4) cracker to bring it to world scale.
The study strongly recommends very close monitoring of at least Delta gas developments and a very strong push to get Delta gas and related C2 plus routed as directly as possible to the Syncrude / Suncor / CNRL area. Reducing gas replacement cost and adding C2C3’s to SGL must be high priorities.
7.5 Timing Factors
The development plan of Steps A Æ B Æ C/D was laid out relative to ability to build when suitable R&D&D were complete and to avoid major peaking of construction at the new site. Step A in total is similar in complexity and capital to Dow’s ethylene plant and related expansions (albeit these were in two stages). Much more activity could again overwhelm the regional construction capacity. Step B is much
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 72 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 less complex and lower in capital, while Step C is larger and more complex due to gasification (and related air separation).
Bitumen availability will build up over time with, say, 400,000-BPD available by 2008 to 2009 period from new projects.
More SGL’s may become available over time, but only those due to coking will be of major significance – watch for CNRL and Husky C3 C4’s – would impact overall planning. At time of writing, upgrading routes beyond 2010 were not defined. The gas cracker C3 plus streams and refinery C3’s are assumed available as early as 2006, but move of the latter are to be expected.
Organization, planning, design, permitting, financing and construction of a new upgrader complete with residue gasification will take until about 2010 and startup in an upgrader only mode will take until 2012. Integration of such an upgrader into petrochemicals will take others 1-1/2 to 2 years – bringing the time horizon near the study’s 2015 time line.
Refinery naphtha comes available only as there is enough alkylate and/or other premium gasoline components available from new facilities about 2010 to displace it for new aromatic production. Light gas oil for ethylene production would only be first available about 2012 from the new upgrader. If heavy gas oil can be economically hydrotreated, it will be available at the same time.
The development – over time – of a major new petrochemical monomer complex with its bitumen, upgrader and refinery ties will only occur in parallel with new monomer consumers. For short periods, movements of excess ethylene and propylene and perhaps benzene to midwest or other market areas can be used, but for full Alberta Advantage to be achieved the majority must be used here – very preferably in high value added derivatives. This study did not attempt to develop a prospective new user versus time profile, BUT such will be essential in all further planning.
The province is showing constraints in its ability to staff and support several mega projects at one time. A gradual buildup of the new petrochemical monomer et al complex is preferable to control capital costs, but petrochemical price cycles may dictate earlier or later on-stream dates.
CMAI have been estimating (crystal balling) 2006 and 2012 margin peaks – and a 2014 completion may prove too late. (See Appendix B) This study did not attempt any analysis relative to such peaks, but notes it best to start up 1 to 2 years before a peak to maximize its profit potential.
7.6 Different Order of Development?
7.6.1 Preamble
It is highly unlikely that development would ever proceed exactly as set out in the Steps A + B + C + D assumptions of this study. The scope of each stage of development will differ in order to best suit economic projections and owner interests.
One critical issue in any staged development is the question of how much do you pre-invest for future stages – in layout, utility / service core, as well as in specific process units? For example, Step A includes general site development to permit easy expansion and its SGL et al fractionation system and C4 complex planned to take various streams from two stages for Petro FCC development. Step B now assumes prebuilding to allow easy / quick doubling of the Petro FCC and the aromatic complex in Step C. Step B is really the first part of Step C.
The preliminary capital cost estimates of this study have assumed such prebuilding in Steps A and B and thus require modification in any other than Steps A + B + C sequence and/or sizing. (Such adjustments cannot be done, by simple factoring of this study’s cost estimates.)
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 73 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
7.6.2 In Step A Expedite New C2 C3 C4 Cracker
The new gas cracker can come online as soon as built, using any surplus NGL ethane with propane and/or butane as base feed as most economic at the time. However, the C5 plus components would need transport to other centers, possibly railed as a mix to the USGC or Sarnia. Note that unless Joffre hydrogen was to be brought in early, the C2C3 cracker’s hydrogen is needed for both propylene purification and saturation in the C4 complex.
7.6.3 Put Step B First
The C4 complex would be added at this time, but this is similar in size and type of units to the aromatics units to be added at this time. However, C2 C3 C4 fractionation would require towers now planned in Step A and final Petro FCC ethylene recovery (100+KTA) would have to be done in Dow’s ethylene plant if capacity could be made available.
Joffre hydrogen is essential for Step B (and to ensure ease of operation), as the gasifier is online only in Step C.
7.6.4 Put Step C First
Step C in the basic scheme of this study is not planned to produce synthetic crude oil, but rather is a refinery / chemical unit producing diesel and feeds for further processing. Step C was put last in the proposed sequence, due to perceived development and construction schedules. The gasification system in particular will take longer to build and bring online to fully stable operation. As noted, Joffre hydrogen will be needed as backup during startup and whenever a gasifier is out for maintenance.
Development planning must consider the regional construction capabilities. A shortage of senior construction supervisor’s and trades people can be overcome in an ongoing, near full employment setting with extensive training and retraining.
At all times, major maintenance shutdowns at existing plants must be worked into planning and the worker needs in such shutdowns can be as great as in, say, Stage B construction. However, in any case, specific project corporate and economic drivers may indicate peaking needs in construction. However, USGC cost levels will not be maintained at such times.
Discussions with various upgrader project proponents indicate that upgrading per se – initially at least just to SCO – step could well move up in staging. At the assumed 156,000-BPD (120,000 of bitumen and 36,000 of HGO’s) and gasification, this becomes a mega project and some form of staging must be considered.
If an immediate start is planned, the Petro FCC should follow along with addition of what’s now in Step A and an aromatics complex. This would bring the Petro FCC online at full design rate, whereas in Step B it would have been running at roughly half its ultimate capacity. However, note that ethylene and propylene yields will be below the targets originally set in this study.
7.7 Business Side Comments
The thinking of this study concentrated on developing and analyzing the technical aspects of selected representative steps in overall bitumen to petrochemical monomer project development. It is recognized that the 2015 grouping of process units is very likely to differ from A + B + C steps, assumptions of this study and that the actual steps will themselves be different both technically and over time.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 74 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 This study was based on assumed major new ethylene, propylene, benzene and p-xylene demands – local markets for the new petrochemical monomers and allied products should in practice determine the scope and timing of development, but surplus products may be transferred to other areas if/as economic.
No detailed analysis has been done relative to how best to organize and carry out the business sides nor government assistance aspects of the suite of new projects. Table 7.7-1 provides a brief one person’s overview of the sectorial expertise now seen as needed relative to key units in Steps A, B and C. These indicate a diverse range of expertise – planning, operating, managing – feed / product supply and logistics that must be fully coordinated and brought into a fully cohesive and, especially, synchronistic whole.
Table 7.7-1. Steps A, B and C Technical Expertise Need Overview Steps Expertise Sectors A Upgrading Refining Bulk Specialty NGL Other Petrochemical’s Petrochemicals SGL Capture (at Site) 33 3 3 SGL et al Fractionation 3 3 3
C3 C4 Cracker 33
C4 Complex 33 33 Utilities 3 3 3 3* Pipelines (SGL, etc.) 33 ** Pipeline Cost Storage (salt cavern) 33 * B HGO HT 3 33 Petro FCC 33 Aromatic Complex 33 33 Utilities 3 3 3 *
H2 Pipeline 33 ** C Primary Upgrader 33 3 Hydrotreating 3 33 (Expand A and B Units)
Gasification (to H2) * 3 3 * new here Air Separation * 3 (a) **
CO2 System Center 3 (b) D Fischer Tropsch Add-on 3 new Utilities 3 * Pipelines (RPP’s, Etc.) 3 ** * Can be subcontracted to specialty operator / owner operator. ** Will be subcontracted to specialty operator / owner operator. 33 Specialties (a) Industry gas company owner / operator.
(b) CO2 system seen as separate entity but operated from new core facility.
Of the Oil and Gas Journal’s list of the top 10 ethylene producers worldwide only Equistar (itself an amalgamation of interests), Chevron Phillips and Sinopec do not have joint venture crackers. [10] Obviously, Joffre’s E3 is the major Canadian example. The new BASF / Atofina / Shell Port Arthur Texas joint ventures in ethylene and coproduct C4 processing were noted several times. (The indirect connection of a Venezuelan upgrader is especially intriguing.) The evolvement of NovaChem Corunna facilities from the SOAP – Sarnia Olefins and Aromatics project, now with Sunoco refinery interties and Canadian SCO refinery feed also need to be considered.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 75 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Page Left Blank
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 76 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 8.0 RESEARCH, DEVELOPMENT AND DEMONSTRATION
8.1 Introduction
This section only touches on the highlights of perceived R&D&D needs and opportunities beyond the prior discussions. Priorities are not discussed as these are best addressed as developers and researchers better define the optional ways forward.
It is essential that Alberta researchers into the bitumen to petrochemical monomers and refined products cycle understand the industrial settings and their future prospects. However, such understanding must not hinder creative thinking towards new value-added products from bitumen. Industry has been prone to lack of promotion of new ideas and related R&D, except internally – and to lack of future business setting communication to outside researchers. Outside researchers seldom “learn” enough about where their results will be used.
The world of fundamental chemistry is evolving at the fastest rate ever, in some instances, fundamental research findings becoming part of commercial products 2 to 3 years, particularly in the case of polymers and occasionally with specialty product catalysts. At the same time, refining and hence, upgrading R&D budgets are contracting. Most breakthrough R&D is now outside oil companies, but the latter are very reticent to accept any claimed breakthrough. (In the past, smaller independent refiners built the prototype units – often without successful operation.)
Ultra high rate catalyst and simple process step screening is becoming the norm and nanotechnologies will accelerate such screening. Except for certain catalysts and their products, generally such high rate screening has led to only small step improvements – but breakthroughs must continue the goal of fundamental and long-range application research. New processes still need scale-up and demonstration – that takes time!
It must be appreciated that very large-scale commercial process facilities will still be developed and usually financed only using “proven” approaches. There have been several recent examples of proceeding on projects before R&D was appropriately advanced – resulting in high-cost overruns. While new catalysts with, say, two years of commercial experience can be used as design bases, newer catalysts may be selected nearer start-up, if, again, already performance proven, but with no unit design change possible. Newer process configurations are generally only step-outs using the design stage catalyst in its best setting and incorporating proven improvements in equipment and in equipment sequencing.
Gasoline, jet fuel and diesel qualities can be generally foreseen into the 2012 to 2015 era. Bitumen processing and bulk petrochemical monomer production will be using today’s/next year’s technologies in large-scale through to 2020 due to the slow equipment turnover. BASF / Atofina’s new Port Arthur naphtha cracker will be in operation through 2022.
This does not preclude new technologies, which will develop, but it does say that the latter are very unlikely to fully displace, say, 2006 era technologies by 2020. There is continual improvement in older technologies – here we consider a new generation FCCU, but the first FCCU units were build in 1941 (parts of a 1945 FCCU continue in use in a Cheyenne refinery running Canadian crudes). Independent new process developers (and government agencies) seldom monitor such developments, often, spending unnecessary effort and time.
There is a major need for an Alberta semi-commercial scale facility to provide acceptable scale data on new and improved bulk processes, acceptable technically and financially. This may still mean an intermediate step up before mega project use, but that, with relatively few players may be difficult. The last “D” of R&D&D is very expensive and buyers may be quite limited, especially in areas covered in this study.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 77 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
This study was largely about production by 2015 relative to bitumen to ethylene, propylene, benzene and p-xylene bulk petrochemical monomers and coproduction of certain gasoline components, jet fuel and diesels, with comments re ongoing R&D. Some attention was given to intermediates potentially available for specialty products. These notes cover:
a) Needs for A + B + C + D commercial development b) Potential improvements to A + B + C + D c) Comments on specialty and other derivatives
In regard to a) the following two tables outline the R&D needs now foreseen re A + B + C + D development. Generally, most such R&D will be by Licensors and/or catalyst vendors, but hydroprocessing and perhaps even FCCU related piloting can be done here. A new process demonstration center would be ideal for certain parts of this R&D – e.g., FCCU recycle to BTX.
Table 8.1-1. Stati of Process Development of Basic A, B, C, D Processes Process Segment Little/No Routine Piloting – At Advanced New Special Notes R&D Need Catalyst Selection Development Process Stage (A) SGL SGL Capture Cryogenic ⎯ ⎯ ⎯ Membrane Option SGL Fractionation 3 or 3 ⎯ ⎯ Treating? C2C3C4 Cracker 3 or ⎯ 3 ⎯ C3= Purification 3 or 3 ⎯ ⎯ Diene Saturation C4 Hydrotreat ⎯ 3 ⎯ ⎯ Diene Saturation C4 Alkylation * ⎯ ⎯ 3Fixed Bed ⎯ Support / PP Verification (B) HGO HGO Hydrotreat * ⎯ 3 or 3 ⎯ What is optimum depth? Petro FCCU * ⎯ ⎯ 3 ⎯ Major pilot need. Light Cycle Oil Recycle * ⎯ ⎯ 3 or 3 Major pilot need. See Footnote on Table 8.1-2. Naphtha to FCCU * ⎯ ⎯ 3 ⎯ Pilot need, Aromatic Hydrotreat * ⎯ 3 ⎯ ⎯ Aromatic Extraction * 3 or 3 ⎯ ⎯ Aromatic Fractionation 3 ⎯ ⎯ ⎯ Hydrodealkylation * ⎯ 3 or 3 ⎯ Transalkylation (T/C9ÆX) * ⎯ 3 or 3 ⎯ Ongoing Catalytic Development P-Xylene Extraction * 3 or 3 ⎯ ⎯ Xylene Isomerization * 3 or 3 ⎯ ⎯ Sulphur Systems 3 ⎯ ⎯ ⎯ FGD * ⎯ ⎯ 3 ⎯ See Marsulex (C) Bitumen Conversion Distillation 3 ⎯ ⎯ ⎯ Primary Conversion = ⎯ ⎯ 3 or 3 Semi-commercial scale Naphtha Hydrotreat 3 Jet Hydrotreat * ⎯ 3 Diesel Hydrotreat * ⎯ 3 or 3 ⎯ # 2 HGO * See (B) #1 HGO Hydrotreat Gasification * ⎯ ⎯ 3 ⎯ Ash Handling * ⎯ ⎯ 3 or 3 Syngas Processing = ⎯ ⎯ 3 or 3 High Temp. Membrane Shift / CO2 = ⎯ 3 or 3 ⎯ H2 Purification * ⎯ 3 ⎯ ⎯ (D) FT Synthesis ⎯ ⎯ 3 or 3 Major ongoing R&D Selected Options for Further Study – Only a Start List Metathesis Æ C3= * ⎯ 3 or 3 ⎯ Reverse of Metathesis Disproportionation Å C3= * ⎯ 3 or 3 ⎯ Naphtha to Aromatics * 3 ⎯ ⎯ ⎯ Naphtha to C3 C4/Aromatics* 3 or 3 ⎯ ⎯ Butadiene Extraction * ⎯ 3 ⎯ ⎯ DPCD Extraction = ⎯ 3 ⎯ ⎯ See NovaChem Isoprene Recovery ⎯ 3 ⎯ ⎯ Naphtha Cracker = 3 ⎯ ⎯ ⎯ Light Gas Oil Cracker = ⎯ ⎯ 3 ⎯ Heavy Gas Oil Cracker ⎯ ⎯ 3 or 3 (See Petro FCC) Specialty Products = 3 & 3 & 3 & 3 Much R&D Needed Naphtha to C3C4+ 3 & 3 Hydrocracking * License process – Mostly Licensor led R&D = May be licensed process(es). – Initial catalyst specified by Licensor
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 78 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 8.1-2. R&D Specifics a) For Development OF A + B + C + D Petro FCC • See table of process stati. • Mostly pilot FCC operations (with licensor help!) (Note concerns re NCUT FCC plants). (a) + pilot catalyst confirmation • Note FCC Recycle Æ BTX piloting need (Licensor or here?) (1) Lower Cost / Better Bitumen • Must recognize value of partial deasphalting in field trials (and bench testing) • Perhaps field studies re where solids from wet steam deposit information. Conversion Options • Prototype Test Unit(s) Essential Tube Cracking • Trials on Deep Visbreaking, Aqueous Visbreaking with/without additives and similar processes (See Figure 8.1-1A) • With PDVSA/UOP/Foster Wheeler? • (Modified) CANMET Emulsion Upgrading with Additives. • HSC / Eureka (Toyo / Chiyoda) • Note need to duplicate (old) metals in distillate versus cracking temperature curves of Washimi. • Any help needed by Opti? Feedback from Opti? • Asphaltene cracking trials. • Other “simple” approaches. Fluid • FCC pilot can be used re fluid coking / 3D / EnSyn to see if full prototype needed – Demo unit essential if attractive – note much more complex than “tube” unit. [33] • Ethylene via catalyst in tubes – up to NovaChem – LG trials, but demo unit prototype Catalyst in Tubes could handle. (a) Re pyrolytic approaches – watching brief only. * (1) Recycle of Petro FCC mid distillate via hydrotreating with possible addition of C10+ aromatic stream from aromatics complex could well result in new unique processing routes. This may well be a major ongoing R&D effort. b) Potential Improvements To A + B+ C + D (Note need for demo unit if not already in place!) Gas Separation New Approaches to Gas Cleanup • University / fundamental at Research Organizations and separation. • New “membranes”,* e.g., for olefin capture (cold?) for COS, H2S from syngas • Rethink use of fuel cells to remove H2 from H2 rich off gases. • Need small pilot. Extraction Technologies • University / NCUT / Others (b) (Adsorptive/Absorptive) Raw Bitumen/Upgrader Diesel • Bench scale tests of: Raw Bitumen Gas Oils • Solvents - Other Hindered Sulphur • Adsorbents - Aromatics • Extraction and Extraction Recovery - Nitrogen Compounds [34] • Related “Raffinate” properties and HT pilot testing to see if lower cost. • Related Extract properties and new studies / tests to see uses / disposal. Deasphalting • See Opti DA / DAO Thermal Cracker Scheme and get update on related R&D&D to Nitrogen Metals etc. in DAO extent possible. • Addition of chemicals to revise selectivities – e.g., Ethyl Acetate to reduce DAO nitrogen. • Low cost DAO metals adsorbent trials. Asphaltene Reduction • Note Toyo / KBR 1988 data re deep thermal cracking before deasphalting (noted above). • Asphaltene thermal cracking trials (see tube cracking above). Fischer Tropsch / Syngas • University fundamental work / ARC et al. Newer Processes • E.g., eliminate on-step in syngas direct to light olefins. New Products • Put raw Fischer Tropsch liquids direct to FCC. • Capture ∝ olefins and/or organic acids. New Catalysts • Consider joint venture with Fischer Tropsch process licensor re further development – or, say, with Air Products or Norsk Hydro / UOP re olefins direct from syngas. Air Separation • Far out ideas to lower energy costs – e.g., special membranes, extension of adsorption to very large volumes. • Fundamentals at university. • Explore far out concepts. Hydrogen Related • University et al • E.g., note membrane type R&D above. • Use of fuel cells to remove H2 before SGL recovery to lower SGL capture costs. • H2S dissociation – needs review to see what may be economic and what is being done today.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 79 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 CO2 • Integrate with whoever will manage CO2: • CO2 EOR R&D&D • Aquifer Disposal (field trials essential) • CBM CO2 outlet • Note many other intermediates will become available. Warranting university and other research. • A two-day working session for University of Alberta, University of Calgary, University of Lethbridge, Syncrude and other researchers identify and review prospects and set priorities. c) New Approaches – Bitumen To Petrochemical Monomers Heavy Aromatics • University / ARC / Etc. Naphthalenes • Define properties of raw feeds. [35] • Pilot hydrocracking as appropriate to next process needs. • Also note FCC recycle (with / without other heavy aromatic stream) to BTX trials. 3 + Ring Materials • Develop long list of “new” product options: • Joint R&D opportunities • New products (to be started here) • electronics (micro-scale) • to aluminum (macro-scale) Æ Think-tank with researchers and wide variety of product specialists to develop priorities. Many new ideas will emerge. [36] [37] Dienes • University / ARC / etc. Acetylene • Define properties of feeds. Butadiene (novel) [38] [39] • Develop long list of new product options. MAPD Î • Joint R&D Opportunities - products - extraction process Isoprene • New products – e.g., specialty electronics. Î Think-tank with researchers and wide variety of product specialists to develop priorities. Metals • Joint with CRI, Gulf, or equal and/or Dynatek? Vanadium, Nickel • Vanadium pentoxide and nickel concentrate from gasifier ash – coprocess with LC Finer spent catalyst. • The following are typical of areas considered as having fundamental research potential for commercial derivatives: Ionic Liquids • Just breaking into related processes (IFP). Do not see in major bulk chemistry for 15 years – we have had 25 to 30 years R&D in Canada. This is an excellent university R&D area – University of Regina has some history – but (Ireland / U.S. / others) moving very “fast” in chemicals area. Microwave • Some local research but dispersed. Note “integration“ with other approaches – e.g., Ultrasonics/Cavitation conventional thermal. Super Critical Flow Fuel Cell Approaches • Chuang’s propane to propylene + electricity good example, but three years university, 4 to 5 years big piloting, 2 years prototype and we are already in 2012 before we can consider commercial scale. However, potential for other fits and spin- off ideas. • Note above suggested rethinking of fuel cells to “remove” hydrogen to reduce cost of SGL recovery (and get more than fuel value). • Hydrogen transfer (in various processes) fundamental research – it is very important in aqueous conversion (old Allied / Exxon reports) and could lead to new ideas for other processes. • At least a watching brief should be in place by AERI to monitor work elsewhere on: i) Paraffin / aromatic direct to second or further stage derivative. ii) Aromatic derivatives k- bulk to nanotubes / buckyballs. iii) Synthesis gas derivatives – major study area elsewhere. iv) Biologics as petrochemical feed and product ingredients. v) Biological desulphurization and denitrogenation and demetallizing. Notes: (a) NCUT may need funding for FCC pilot – be sure it covers needs of Petro FCC type piloting. (b) See University of Pennsylvania reference diesel extraction treating and BP Reference reoxidative desulphurization. Check GTC re their progress on diesel et al extractive upgrading – see Gentry letter to Editor in July Hydrocarbon Processing. * “Membranes” = any “material” that will selectively pass desired or undesired components. For example, “Nature”, June 20, 2002, “Porous Materials of the Future”, page 813, review article, has wide range of examples and Research Triangle has new approach with large molecules going through. (However, 3 to 5 years of small-scale commercial proof needed before any large-scale use.)
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 80 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Figure 8.1-1A
LOW COST CONVERSION OPTIONS TO BE EXPLORED Basic Data if Study Positive Prototype Trials
• Hydrogen Addition to Visbreaking • Shell Deep Thermal Cracking - Similar to above • Aqueous Visbreaking - with/without additive - Flow as above (with water/chemicals?/catalyst?) - various versions • CANMET EMULSION UPGRADING - (NEW Version?) •HSC/Eureka N atural G ases
MGO Fractionator Atmospheric Bottoms Feed HGO Vacuum Bottoms
Eureka uses Visbreaking parallel batch Furnace Stripper hold/strip vessels. Hot Steam Note that Gasification with Fischer Tropsch Conversion. Pitch to Gasification
Figure 8.1-1B
Metal Mild Hydrocracking Atmospheric Traps D istillation NEW Deep D easphalting
DEASPHALTING Pitch to Gasification
Gases
Thermal Atmospheric Cracking D istillates to H T D istillation NEW Mild D easphalting Bottoms Recycle OPTI Gases + Optional Asphaltene Cracking Thermal Cracker Optional Add-on To Opti Scheme
To Gasification
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 81 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 8.2 Bitumen Supply Research & Development & Demonstration (R&D&D)
Any bitumen to chemicals and/or refined products scheme will be very dependent upon the quality of the bitumen as well as on its price. Any/all field prototyping of new in-situ approaches to lower production and utility / steam costs in to be encourage.12
The study’s economic bases do assume some improvement in SAGD type production fuel consumption due to the developing of low-pressure approaches. However, there is a need for the question of “pure steam or 90% steam” injection to be answered considering the whole production envelope. 90% steam can result in reduced fuel costs in such analyses; however, this may mean further studies on where solids are left when impure steam is used.13
Solvent approaches to in-situ production were not considered here for basic complex feeds as generally usable results of current and future projects will be several years away. However, more or less partially deasphalting appears inherent in such approaches, but not necessarily recognized as a major prospect for value enhancement. Leaving more or less of the asphaltenes in the formation or mine should be a major R&D&D objective. Obviously, there is an economic breakpoint, but to date only recognized in the Albian mining project and as proposed for Fort Hills. There are major economic incentives throughout the systems to optimize the asphaltene content of the product.
Reduced asphaltenes reduce final upgrading capital costs whether the process is thermal – e.g., coking, 3D, EnSyn, visbreaking or hydrogen addition. Yields of valuable products stay essentially constant per barrel of original bitumen, but due to reduced “crude” viscosity and volume, pipeline costs and any diluent needs drop. The partially deasphalted material handles much better in upgrading and refining. Overall, life cycle greenhouse gas costs are generally significantly reduced.
The challenge does not appear so much of new R&D needs, but rather recognizing the value of leaving more or less asphaltenes behind as lab and field R&D&D are carried out on new in-situ and mining approaches.
8.3 Primary Upgrading Options
The study assumed a simple deep visbreaking route, partly as its yields were considered relatively easy to judge. It was recognized at the time that better distillate yields and less pitch could probably be produced via other options. The pitch yield was of special concern due to the very high capital cost of gasification and attendant air separation and synthesis gas to hydrogen facilities.
Ironically, the very high hydrogen yields of the original scheme could match hydrotreating needs of 500 to 600,000-BPD of raw SCO materials, assuming it is done in the “south”. Also, ironically, with Fischer Tropsch liquid production using the same hydrogen the overall liquid yields from the suggested AT B + C + D scheme are among the best available at over 90% of bitumen (except as may be possible via very expensive very deep residual hydrocracking). Capital costs are still high.
The study was disappointed that good public data were not available for a range of bitumen deasphalting operations. Deasphalting presents a major challenge due to carryover of metals in DAO to subsequent hydroprocessing. The T-Star hydrogenation processing is the one option for this with its regular catalyst makeup and withdrawal – but a second deeper hydrogenation step would still be needed. Opti Energy have added a DAO thermal cracking with bottoms recycle to deasphalting in their proposed process Long Lake upgrader scheme, but piloting continued at time of writing.
12 With partially deasphalted bitumen a primary conversion process may not bee needed – considerable process simplification is possible. 13 CO2 EOR can have a similar asphaltene issue to bitumen per se but it is very seldom recognized.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 82 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Various enhanced visbreaking type processes – aqua conversion, aqueous visbreaking per se, CANMET emulsion conversion, hydro visbreaking, HSC (high severity cracking), Eureka (similar HSC) and Shell deep thermal conversion were typical options without available Athabasca bitumen yield data. In all these cases, while bench data are easy to produce commercial scale data are essential to demonstrate good performance with good yields – due to minimum tube and many process equipment size constraints. They all appear to offer higher distillate / lower pitch yields at much less cost than residual hydroprocessing. As will be discussed later a demonstration facility is strongly recommended.
Multi stage thermal cracking can be used to produce distillates and fuel gas from heavy crude oils. It is possible to add a cracking step on asphaltenes from deasphalting – reducing the pitch volume, producing fuel gas and some very aromatic distillates while the viscosity of the pitch may actually decline making it easier in gasification. Such an option is recommended for piloting if deasphalting is considered for primary upgrading – but it could be a pitch reducing add-on at any time.
8.4 Pyrolytic & Catalytic Approaches to Ethylene, Etc.
Matar and Hatch in their first version of “Chemistry of Petrochemical Processes” had many pages on pyrolysis approaches to ethylene and acetylene. [26] But those pages have all disappeared in the 2001 second edition except for a continuing note that reducing residence time offset by higher temperatures increases acetylene yield and the latter is the stable product at high temperatures (recoverable only with very rapid quench). [27]
Hüls plasma arc acetylene production at Marl used propane and butane as quench with appreciable ethylene production. The BASF partial oxidation of methane route to acetylene claimed an ability to use very aromatic distillates as quench producing benzene. However, an ex Lurgi specialist advised this study that that route did not work in the last (1978) unit built. In both processes handling the very fine acetylene black in the separation sections of the plant is a major challenges, as observed at Marl by one of the authors.
This study did not find new pyrolysis approaches that appeared to match a bitumen to petrochemicals cycle. A watching brief is recommended with operating results of most importance – although lab scale claims can generally be discounted.
8.5 Integral Fluid Bed Cracking / Gasification Development
LC were building a $300,000 (U.S.) pilot unit to test a catalyst in tube approach to increase the ethylene from naphtha yield by 20%. There are numerous references to prior R&D on such routes, but none have matured further as far as this study can determine. a) Fluid Coking Per Se
The Exxon Flexicoker concept integrates a simple excess coke gasification (with air) step to produce a very low heating value fuel gas (LHV only 15% or so of natural gas) at very low pressure from the excess coke byproduct. There are five major units worldwide. This process is generally considered expensive and very difficult to operate. The very low BTU fuel gas is difficult to desulphurize (note COS in significant quantities) and to economically burn more than, say, 100 meters from the gasifier. This low BTU gas is also largely carbon monoxide; hence, its combustion releases large quantities of CO2 in flue gas from the boiler or furnace consumer. The gas pressure is too low for gas turbine use without very expensive compression.
The study team believes that the current high severity of conventional fluid coking is not very conducive to high value hydrotreated derivative production. The side chains on the bitumen get knocked off leaving largely aromatic derivatives. (SGL recovery will pick up many of these at Syncrude – and processing of Syncrude naphtha in the new complex would pick up more useful
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 83 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 butene and some butadiene components.) As noted later, a less severe form of fluid coking may be attractive, but testing of concept has been long delayed due to lack of suitable small units available to make the appropriate changes.
Figure 8.5-1. 3D with Excess Coke Gasification
Low Pressure Low Pressure SynGas Flue Gas Case Kiln Reaction
Product Recovery Liquid
Air Steam
Excess Coke Hot Coke/Carrier Oxygen Bottoms Recycle Carrier
Recycle Makeup
Metals Rich Waste
b) 3D and EnSyn
The 3D process, now owned by UOP, and the EnSyn process are essentially short cracking residence time / low severity fluid coking processes – both using a non-catalytic coke carrier (carborundum or sand). In these processes, a portion of the product coke is burned with air in a fluid bed kiln to produce hot coke / carrier recycle to provide the heat of reaction (as in fluid coking). From the very limited public information available it would appear that each of these processes tends to produce a raw liquid product heavier in boiling range, but less thermally “attacked” than that from fluid, in particular, and delayed coking – i.e., the heavy gas oil portion is 50% or more of the product. A small residual yield is also apparent, but this can possibly be recycled to extinction producing more net coke.
The 3D process was demonstrated by Coastal at 15,000-BPD in a Kansas FCCU.
The EnSyn process is being touted as a partial-upgrading route based on small-scale piloting and unsubstantiated (by this study team) yield quality and economic claims. It is said to be similar in cost to a catalytic cracker without the catalyst.
The net coke can be burned in the kiln used to produce the hot coke / carrier recycle, but much added heat must be removed from the fluid bed kiln and the hot high SO2 flue gas must be desulphurized and the heat recovered. Alternately, the net coke can be burned or gasified separately (but that does not eliminate the flue gas from coke burning with air for process heat). The 3D and EnSyn routes may offer significant potential when coupled with oxygen gasification to useable, albeit with high compression needs, synthesis gas – but only at large-scale. A 1992 UOP paper suggested gasification of excess coke with steam, the new process looking something like:
It would also be possible to use oxygen in the kiln, but temperature control and heat extraction would be very difficult and explosion risks very high “Dynacracking”. (Flue gas recycle as quench is one option for control.) HRI had such a process concept in the 1980’s, but (fortunately for safety reasons) it has disappeared from the scene.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 84 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 c) 3D Footnotes
In the early 1990’s the at the time developer 14 of what is now 3D switched his development to FCCU per se using the 3D hot solid / feed SRT contact device – three such reaction systems have been licensed up to 70,000-BPD. Coastal surveyed Alberta refineries to see interest / potential in converting existing FCCU units to 3D – at 40 to 50% of FCCU nameplate when feeding available residuals. This interest dropped off and Coastal were unable to finance their own high-yield “proven” process at commercial scale in Aruba – going to conventional delayed coking. UOP advise they are doing little further development and not marketing this process. d) Commercial Proofing
These processes are complex and at least a small semi-commercial scale unit is needed to complete development and prove up economics – even without excess coke gasification. The study likes the prospects for high (but heavy) distillate yield potential in large-scale bitumen to chemicals setting.
Both 3D and EnSyn processes require flue gas desulphurization – probably similar to the high- efficiency Marsulex ammonia scrubbing system being installed on Syncrude’s third fluid coker. Like modern catalytic cracking units, the flue gas would drive the air blower and heat recovery – from kiln and flue gas – would be of major economic importance.
8.6 Gas Separation Technologies
The following are but a few of the many challenges noted in the study that could significantly improve economics in bitumen processing to chemicals: a) Hydrogen Recovery
While membranes have generally proven themselves, there appear to be needs for test systems in upgraders supplanting or integrated with cryogenic SGL capture.
A H2 / C1 / C2 plus split is desired and a suitable system with three plus year membrane or equal life in a sour gas / olefin setting would appear to have major value. b) Olefin Recovery
Membranes have yet to prove successful in recovery of C2 and C3 plus materials from sour gas streams. Past trials of special membranes have not shown sufficient life before performance dropped off. Possibly, this study overlooked further trials, but non-cryogenic SGL recovery, particularly of ethylene and propylene may have great economic potential. Note that membranes are also being developed for materials as heavy as naphthas. [40] [41] [42] c) Hot Syngas Cleanup
Removal of sulphur species is essential before all Fischer Tropsch catalysts and a high temperature route could significantly aid Fischer Tropsch economics. It is appreciated that there is significant ongoing research in this area in the U.S., but no breakthroughs have been noted.
8.7 Extractive Technologies – Liquids
Solvent extraction of benzene and toluene is standard when processing catalytic reformer and other aromatic-rich naphthas, but new solvents, new system configurations continue being found (today usually
14 The 3D process had its start as the ART process of Ashland and later Engelhard and operated semi successfully at the 50,000-BPD scale in Kentucky. Coastal revised the reaction system for the 3D version.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 85 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 by process Licensors). Such extraction can be extended to or almost to the naphthalene boiling range. UOP has a process to adsorb n-C6 to C8 paraffins from naphtha streams as feed to increased yield naphtha-cracking yields. UOP and others have adsorption systems for higher paraffins and to recover p- xylene from mixed xylene streams. Phillips has new processes to adsorb sulphur species from catalytic cracked naphthas and diesels – to meet 2006 30 and 15-ppm sulphur specification levels, respectively.
Solvent deasphalting separates the more paraffinic portions of bitumen and similar residual hydrocarbons from asphaltene type species with more or less separation of other compounds. [43] Crystal melt / freeze technologies are regularly used in naphthalene purification. A recent India/U.S. reference noted that adding ethyl acetate in deasphalting could materially reduce nitrogen in the DAO. [44]
However, other than deasphalting, generally extractive technologies appear to have been neglected relative to bitumen and derivative value addition. Many years ago CANMET did some tests on absorption of nitrogen species from bitumens, but the work did not continue. Heavy aromatic product opportunities and heavy gas oil catalytic cracking potential are noted throughout this study and extraction technologies via R&D could well fit in to provide better, cleaner feedstocks. (With gasification there is an inherent internal disposal route for the “new” byproducts, but the latter could well become valuable products in their own right.) [45]
Extractive technologies are generally easy to test and pilot in university and other laboratories, although the upgraded product will need piloting in its next process. For example, chemical extraction (possibly with reaction) could be targeted at sterically hidden sulphur and nitrogen – and this is being done in a few U.S. trials (with generally only confidential data) on diesel. The resulting aliphatic sulphur can be readily removed in mild hydrotreating.
A solvent approach to upgrading gas oils before or after hydrotreating, perhaps starting from older lubricating oil solvent extraction technologies could well be an alternate route to very deep hydroprocessing of middle distillates to high cetane, with the byproduct to gasification or possibly coking processes.
A simple process for metals removal from deasphalted oil (DAO) and from vacuum distillates prior to hydrotreating would be of very major value. Deasphalting yield suffers badly without such a step and metals deactivate hydrotreating catalysts. A cheap adsorbent, perhaps in a low-pressure hydrogen atmosphere, is needed, but easily / safe / fast adsorbent charge is essential – moving bed?
This study strongly recommends R&D into extractive approaches to “upgrading” raw, cracked and hydrogenated materials towards lower cost SCO, diesels, with prehydrogenation extraction also focusing on reducing hydrogen and severity needs in final hydrogenation.
8.8 Further Derivatives Research & Development
8.8.1 Aromatics
This study was about aromatic starting materials and many intermediate aromatic streams and byproducts. Aromatic issues / potentials will be with us as long as bitumens are produced.
The Petro FCC will introduce major new C10 plus aromatic streams; the two existing Edmonton refinery FCC units already produce similar aromatic streams. The aromatic complex will also produce a variety of C10 plus aromatic streams.
In the 1970’s, Gulf Canada developed two new routes to conversion of aromatic FCC bottoms to synthetic coal tar as a binder in the aluminum industry. [46] That industry was not very receptive at that time, but today a large share of such binders is synthetic. Possibly, this idea could be extended to include a
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 86 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 prebaked electrode plant in Edmonton using bitumen / FCCU derived aromatic feeds and coke produced from bitumen processing at Petro-Canada’s Edmonton refinery.
We see high value-added derivatives of these heavy aromatics as major Alberta products in the future. Mitsubishi Gas Chemicals, Riley, Rutgers and others have major expertise in such aromatics and derivatives, but usually from a coal coking liquids base. The coal liquids and gasification industries could well have many clues for us – but our materials are usually different chemically.
8.8.2 Non-Aromatics
This study was not about non-aromatic chemical derivatives beyond conventional petrochemical monomers, but occasionally potential for new derivatives both from such monomers and bypassing the selected monomers were observed. Alberta applied research generally bypasses these options, but much related fundamental research is evident everywhere. In order to support a broader / deeper chemical economy in Alberta enhanced linkages of fundamental research to and through applied chemical derivatives is recommended.
A review of Nature of opening the C-H bond is a key overview of the still early R&D nature of “understanding and exploiting C-H bond activation”.
Direct oxidation of paraffins and of monolefins and aromatics is of growing interest and direct paraffin oxidation will in time back off some ethylene and propylene demands, e.g.:
Ethane to Acetic Acid • Now approaching commercial status. Benzene to Phenol • First commercial facility (in Florida) delayed two years ago due to markets. (Note: Phenol is the major petrochemical import into Alberta.) • Direct oxidation may be better than cumene route in less than world scale facility. Propylene to Propylene Oxide • Integration with styrene production now standard –SMPO / POSM. • BASF announced new 300-KTA plant using hydrogen peroxide from new Solvay plant. • Degussa said year ago they would joint venture such a plant here using their own technology.
• Could University of Alberta’s K. Chuang’s simple H2O2 process (to 15% H2O2) add propylene oxidation without need for H2O2 distillation? Karl said idea might be worth pursuing. (This is typical of the need for dialogue and crossing of ideas between industry and academia.) [47]
Oxidative approaches to distillate desulphurizing are also well advanced in various laboratories. [48] [49]
While this study found no other related near/at commercial status related process development we expect (near) breakthroughs in operating company and catalyst vendor laboratories, but unreported; good ideas are kept in-house and licensed only when not big enough winner for proprietary use.
At least a strong watching brief is needed on potential production of chemical derivatives from other than the basic petrochemical monomers. University research here should be developed to insure fully knowledgeable scientists for assistance in considering future chemical risks and opportunities and in defining further appropriate work in Alberta.
8.8.3 CO2 Notes
This study agrees there is some R&D but mostly demonstration need and reservoir studies needed along with a strong business plan to use the surplus CO2 from a new bitumen to petrochemicals complex in CO2 EOR and, perhaps CO2 in coal bed methane production.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 87 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
An aquifer disposal test program appears a backup necessity, but generally, CO2 use / disposal R&D has not been considered in this study.
8.8.4 Biological Processing
More than a watching brief is recommended re biopolymers and conventional monomer / biopolymer blends. By 2020, these could well be displacing some of the polymers we know today.
DuPont will be producing propanediol for PTT from sugars in a year or two; but Shell’s new Montreal PTT plant will be using propanediol produced from ethylene oxide at a Texas plant site. Most polyols used in polyurethanes are of biological origin. Canola oil and derivatives are also very likely polymer additives – with some current Alberta R&D.
Biology is being tried in Alaska to remove sterically hindered sulphur in diesel to permit simple low- pressure hydrodesulphurization, but we are told the reaction is too slow for near-term commercial use.
The federal and some provincial governments are trying to push ethanol and various biological origin esters into gasoline and diesels. The latter could who result in significant glycerin coming available for chemical use. At time of writing, the Saskatchewan government was issuing regulations requiring 10% ethanol in their gasolines by 2007.
A detailed study is warranted of biochemical threats and opportunities and of how to meld the latter with bitumen to petrochemical derivative operations.
8.8.5 Inorganics
The metals contents of gasification ash will require process development research by, say, Fort Saskatchewan’s Dynatek and proponents of upgrade spent catalyst processing. This can develop into a major new Alberta industry. Shell’s CRI joint venture has a new solvent extraction process for the latter and a small plant recovered vanadium from Suncor ashes for a few years in the 1990’s. The economic drivers are largely environmental – vanadium is in over-supply and onsite nickel purification uneconomic.
8.9 Research and Development and Demonstration Economics Notes
It must be remembered that existing technologies improve and the delta new to the best existing may not be enough to get financial support for a new route especially at 50,000+BPD scale. Above we are noted one such case and one ethylene producer noted he stopped his R&D re catalytic dehydrogenation as the potential gains were insufficient when he considered his own developments in conventional cracking. However, we always hope for the mega breakthrough.
Reducing the cost of the new complex by leaving asphaltenes in the field and by lowering the costs of the principal feedstocks, bitumen and heavy gas oil and synthetic gas liquids – via mostly incremental technology enhancements appears a paramount research objective with savings of over $500 million Canadian in capital and up to about $0.02 Canadian a kilogram of principal products tentatively available.
Improvements in primary upgrading through R&D&D to prove up a new higher yielding route could also contribute capital operating cost savings at least of the same order of magnitude.
Bitumen to petrochemicals will present many opportunities for Alberta special products with heavy aromatic and butadiene derivatives (dicyclopentadiene and similar compounds could be a real winner.) R&D here should build on external expertise and ongoing producer R&D. (NovaChem for example have specialists re DPCD.)
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 88 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Potential conversion of synthesis gas to a series of derivatives opens up a whole series of possible derivatives with some local R&D, but likely with major R&D done in established process licensor pilot plants beyond the province.
New extraction technologies of SGL’s and impurities in bitumen related streams offer significant opportunities for lower petrochemical monomer costs.
Endnote: University and research organizations staff and their research must be integrated into the bitumen to petrochemical potential – without blinders, as breakthroughs usually come from out-of-box thinking.
8.10 Scale Up And Demonstration
8.10.1 Introduction
One major stumbling block in new technology integration into the large-scale bitumen processing, refining and petrochemicals cycle is the lack of suitable large pilot plant/small demonstration plants to improve on and scale up worthy prospective projects – and to train technical and operations staff.
It is also very important to note that potential for major new processes in Canadian bitumen conversion is limited to 2 to 5 units, whereas there are over 500 refineries worldwide offering markets for new refinery processes. This makes new process development very expensive per potential sale – and there have already been at least one instance here – the DRB process – (paralleling the 3D experience in the U.S.) – of non-acceptance by management of the operating company developer of what might have been breakthrough technology, in both cases after major R&D&D investment. [46]
8.10.2 Demonstration Stage
IFP developed a suite of small demonstration refining units at Lyon in the early 1980’s. These did not prove economic in terms of Lyon operations, but did provide extensive data on a variety of new upgrading options, including Gulf Canada’s DRB (Donor Refined Bitumen) process.
One of the authors had a series of discussions with Exxon in the early 19op’s of why they had not developed a riser cracking (or equal) version of fluid coking to increase distillate yields. The answer was always that no suitable smaller commercial unit was available for such trials. Such a unit would be of major value, even today to Syncrude, as they install a third fluid coker at a mega 100,000-BPD per unit scale. (As noted above, there is always a caveat on SGL availability from Syncrude as distillate yields are their primary objectives. Higher distillate yields generally equate to a heavier boiling range, but less stripping of paraffinic side claims and reduced condensation to high boiling aromatics and asphaltenes.)
LG’s $300,000 U.S. – literature figure but feels low – Korean pilot operation to test a catalyst in tube approach to naphtha cracking for ethylene is a good example of current R&D at a scale sufficiently large to permit commercial scale trials in two years. [22] [23] Earlier U.S. proposals for a similar facility never did develop as far as could be ascertained in an in-depth search by this study’s team. [50] [51]
Thermal cracking processes in general – whether for ethylene or for bitumen upgrading – require at least two and often three-inch tubes to confirm tube fouling tendencies, an area where pilot plants very seldom use more than electrically or hot sand bath heated tubing. Obviously, the “large” tubes must have suitable feed and product off-take systems to them to be of value. (But such a tube system would be useable for catalyst in tube tests, such as that by LG – and for a variety of conventional thermal conversion processes.)
There will be the odd case where commercial units can be used to demonstrate a new process. PDVSA modified a refinery visbreaker to demonstrate Aqua Conversion with Venezuelan very heavy crude
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 89 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 feedstocks. (However, as no tests have been run on Athabasca bitumens at any scale, it is unrealistic to try to convert Venezuelan data here beyond saying Athabasca testing is strongly recommended. If suitable data had been available, it is very likely it would have been used as the primary conversion process in this study.)
One long shot in full-scale testing – the crackability of certain bitumen derived gas oils would be to produce a special gas oil product in Sunoco’s Sarnia hydrocracker from selected SCO feed and have it processed in one of the NovaChem Corunna furnaces. The logistical challenges of such a test program and the difficulty in testing ranges of hydrocracking depth and cracking severity would be major.
8.10.3 Lack of Large Pilot Units Here
University and most other research organizations cannot go beyond bench and very small-scale piloting and that primarily relative to fixed catalyst beds (and universities cannot handle noxious gases at any scale). NCUT is installing an FCCU pilot system, but the study has reservations on its applicability to the high temperature Petro FCCU envisaged in this study.
The study was surprised at the breadth of upgrading research spread around Alberta – but mostly in small micro test facilities and towards (the utopia(?) of) partial upgrading. Two of the team visited a significant field pilot / demonstration unit two years ago, but found a lack of support (and lack of understanding of if/how the product would be accepted in pipelines and by refiners). In that case there were, as always, some good ideas for use elsewhere, but due to the R&D structure, they will disappear. There is a major lack of resource through final product use understanding in most bitumen-related research we have seen.
No large-scale pilot or demonstration units appear to be present in Alberta to suit the needs of the new bitumen to petrochemicals industry, as foreseen in this study.
8.10.4 Training
Most Alberta process plants are facing retirement of senior operation staff and the major new oil sands related ventures will require new staff at all levels of the organization.
The challenges of new staff – even “transfers” from existing plants – and new processes are/will be very major. Operating training courses at Keyano College, NAIT and (starting at) Red Deer College are a major Alberta plus, but do not provide the depth needed relative to new technologies – that is learned on the job. New engineers and chemists seldom have much depth relative to actual operations and it takes several years to bring such staff to usefulness even with experienced senior technical staff (who are becoming thin).
8.10.5 New Development Facilities
An advanced new process test center is strongly recommended to both assist in development and provide commercial scale up data for new/better routes from bitumen to RPP’s and chemical processes and for processes being “relocated” to new feeds and/or new product objectives. Such a center would require analysts covering the spectrum of impacted economic sectors to best place the research and senior specialists to both develop and new process and train technical and operating personnel involved in its commercialization.
This is not entirely a new proposal – both a hi-test center (smaller-scale than Lyon) and an extraction test center (with an upgrading cell) were considered in the early 1980’s. The needs to add chemical industry programs and expertise, as well as small prototype scale equipment beyond NCUT’s current facilities are
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 90 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 to be noted. 15 The training role on new processes and in general, for new senior operations and new junior and senior technical staffs will be especially important.
8.10.6 Asian Cooperation – A Thought
The virtual demise of smaller independent refiners in the U.S. has removed the prior test beds for most new refining processes.
Indian tests on chemical additives to improve deasphalting was noted in review of recent literature.
In this report reference has been made to Korean R&D&D – LG’s catalyst approach to ethylene, the Zeolyst aromatics feed paraffin removal process also comes from Korea – and to Chinese work on deep catalytic cracking. Indian work on deasphalting was also noted. Organizations in these countries appear more amenable to prototype process units to complete commercial proofing and to demonstrate operation than companies in Europe and North America.
Should there be formal collaboration / piloting with Asian country organizations in selected segments of the bitumen to petrochemicals cycle?
8.11 Research and Development and Demonstration (R&D&D) in Summary
There are many prospective R&D&D areas each with needs:
Bitumen Supply • Quality • Cost Primary Conversion • Demonstration of low-cost option at semi-commercial scale. Integral Conversion / Gasification – Potential? (and fluid bed conversion in general) • Improvements and semi-commercial demonstration. Gas Separation Technologies
• SGL and H2 capture • Syngas sulphur capture Extractive Technologies • Stretching into many conversion and intermediate upgrading areas. Competitive Routes • e.g., direct oxidation bypassing conventional monomers / perhaps biological. (Perhaps “Competitive” is the wrong word?) New Product Development • Heavy aromatic derivatives, ash handling, etc., etc.
Fixed bed catalyst improvements can usually be pilot plant proved but any other type of reaction system requires major scale-up. A major apparent need is for a demonstration center of a scale acceptable to senior management (and probably financiers) to show that new processes and/or new process wrinkles will work in a large-scale commercial plant.
As noted, this study did not attempt to prioritize research, in part, because Alberta researchers should be active in all the above areas and in part, as formal bitumen to chemicals development profiles evolve they will have their own priorities.
15 Consideration might be given such a center in unused portions of the Celanese Edmonton plant, with its excellent infrastructure and support facilities.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 91 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 9.0 SUMMARY
9.1 Introduction
This study was sponsored by Alberta industries and government agencies to identify potential for major value added petrochemical production from Alberta’s massive bitumen resources and to define the appropriate related research and development and demonstration directions.
The study’s geographic envelope extended to the West Coast and its industrial envelope as far as gasoline/jet fuel/diesel with existing Alberta ethylene production byproducts assumed available. (This study did not consider production of SCO per se.) An interactive approach ultimately led to a basic three step development plan to form an analytical base, largely based on a fully integrated multi unit facility on, say a section of land somewhere in the Redwater, Bruderheim, Fort Saskatchewan triangle (Alberta’s Industrial Heartland). Such a location would take advantage of major pipeline integration, existing chemical plant integration potential, Williams synthetic gas liquids (SGL’s), SAGD production (hot?), Joffre (hydrogen and ethylene production byproducts), as well as local A new line to Vancouver appears needed due to many issues related to carrying batches of industry. refined products in a crude line when product sulphur specifications drop to 300-ppm A major new pipeline was assumed carrying certain products gasoline and 15-ppm for diesel in 2007. Isooctane from Alberta EnviroFuels plus to Edmonton at rates matching Enbridge’s clean product line 75,000 plus BPD of existing movements and those of a new TransMountain clean products line to would avoid reprocessing with the new line Vancouver. The latter would permit shutdown of a and over 90,000-BPD of new SCO delivery Vancouver refinery, and as noted later supply of very capacity would develop in the existing line to environmentally gasoline and diesel from the suggested Washington state refineries. complex to Vancouver markets.
9.2 Principal Products
Somewhat arbitrary minimum targets of 1,000-KTA (thousand tonnes per day) for each of “new” ethylene and propylene, 500-KTA of new benzene and 300-KTA of para-xylene were set for an effective bitumen to petrochemicals effort. These rates correspond to one or two world scale new derivative consumers for each monomer (with some ethylene and propylene available for smaller scale derivative project needs).
Markets for up to 50,000-BPD of new jet fuel and diesel appeared available, largely from the above-noted refinery shutdown and up to 30 to 40,000-BPD of gasolines or even more of alkylate due to prospective California markets. Naphthas may be a problem, but markets were assumed at light crude par in bitumen dilution. (There are a variety of options noted later to eliminate naphtha production per se if needed.)
9.3 Feedstocks
Almost unlimited bitumen could be made available, but arbitrarily 120,000-BPD of in-situ based bitumen was assumed for the base study case. To this 4.3% of the 700,000-BPD of projected Syncrude and Suncor 2007/2008 total synthetic crude oil production was assumed as available as a heavy gas oil/vacuum gas oil stream – distillates, but boiling above diesel. Another 6,000-BPD of similar material were estimated available (by trade) from new regional hydrocracking based upgraders. Ethylene and heavier components of coker-based fuel gases were assumed available from Syncrude and Suncor (in a 2008 context), extending the existing Williams Energy system to ethylene and ethane and additional SGL’s at Suncor. Existing ethylene plant's byproducts were assumed available (except for previously committed hydrogen streams). Certain refinery propylene and xylene-rich streams were assumed available as feeds to the new complex. More or less natural gas liquids based mixed butanes were assumed available to meet any incremental butanes needs in one of the base case processes.
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 92 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 9.4 Basic Process Scheme
A 3-step approach was assumed for analysis and as recommended to smooth out construction peaks at the new site. The need for some piloting and other R&D was also noted, possibly stretching some development.
Deep
LIQUIDS ORIENTED PROCESS Hy droprocessing Light Heavy Add on at two Naphthas Gas or more USGC C3 C4 Gas Oil Oil Siites FLEXIBLE FLEXIBLE FEED CRACKER Up to 1,000-KTA Ethy lene plus: Propy lene, Butadiene/Butalene, Aromatics and Fuel Oil HGO’s
CONVENTIONAL Bitumen SGL’s HGO’s Processing
Deep Hy drotreating GAS CRACKER
Possible NGL C Petro C C 3 2 3 Add-on FCCU PROPOSED AERA
800-KTA 1200-KTA Pitch Propy lene Propy lene Buty lenes Ethy lene Buty lenes Hy drogen Aromatics Heavy Aromatics (some ethylene)
The near-term value of hydroteated naphtha (at least initially) and of middle distillates from bitumen conversion were considered too high for cracking, but both could be cracked if desired. However, much more R&D&D is needed before the economics of bitumen derived heavy gas oils as feed via conventional furnace or catalyst assisted cracking can be defined.
Step A assumed 2007 SGL availability along with ethylene plant C3 C4’s and some refinery C3’s. The 76,000-BPD of A SGL SGL’s yield some ethylene and enough ethane to crack to 2007 about 400-KTA of ethylene. Also, there is a very significant C propylene contribution and enough propane to crack to another 2011 UTILITIES 400-KTA of ethylene. Thus, a new C2 C3 gas cracker was assumed. Serv ice B HGO 2009 The C4 components were assumed converted to high octane alkylate for use in gasolines (perhaps as far as California). The SGL/PCC A alkylation unit would be a new generation fixed bed design – SGL Frac C2= one of the 2 or 3 such units worldwide at time of construction.
C2 C3 Cracker C3=
C4 Alkylation NGL C4 Alky Cracker
PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 93 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003
Step B added heavy gas oil processing with excess Joffre Al k y l a t i o n hydrogen for hydrotreating low quality heavy/vacuum gas oils C4 = + iC8 iC8 to a level suitable for a new Petro FCCU emphasizing Alky late - 105 Octane (Regular Gasoline 97) propylene, butylenes and light (BTX) and heavy aromatic - No Olefins - No Aromatics products with some ethylene. The severity of this unit would - No Sulphur be above virtually all current FCCU’s and the feedstock unique Clearset gasoline possible today (with C4 and paraffinic naphthas. – piloting is needed of feed hydrotreating and the Petro FCCU per se. (A new catalyst may be most appropriate.) FCCU = Fluid Catalytic Cracking Unit BTX - Benzene, Toluene, Xylene A unique feature recycling some of the heavy aromatic B fractions for cracking to BTX has been assumed – again more HGO HT piloting needed. This step also integrates BTX-rich materials VGO from the existing ethylene units and surplus xylenes from one Naphtha Aromatic Petro- Complex Benzene Step C adds bitumen processing via a simple deep chemical P-Xylene visbreaking or equal conversion process. Its raw naphtha, jet Aromatics fuel, diesel and heavy gas oil products are hydrotreated with Heavy Aromatics the latter adding to Petro FCC feed. The residue is gasified to Bitumen C hydrogen and CO2. (A major air separation unit provides oxygen to gasification.) The conversion process needs much NHT Naphtha research and development and demonstration (R&D&D) and Jet Fuel extensive hydrotreating testing will be needed. Conv ersion JHT Diesel DHT Note that core utility, storage and service facilities expand with Pitch HGO each new step. HT Petro FCC H2 O 2 Gasification CO2 Step D – Fischer Tropsch Addition Air Separations While the economic analysis indicated that a Fischer Tropsch synthesis gas to liquids addition may slightly reduce D economics, the amount of hydrogen Case C may not be n(2H2+ CO) (CH2)n + nH 2O marketable and CO2 yield is borderline relative to CO2 EOR Fischer Tropsch potential (as predicted by others) – hence, some might have to added go to disposal at cost (à la sulphur). to Original Scheme The Fischer Tropsch route also recaptures a large portion of = water needed in gasification and reduces water intake by the Better Environment complex. The Fischer Tropsch diesel is 60+ cetane – an ideal Due top very clean product, e.g., addition to the 50+ cetane assumed from Step C, perhaps Diesel >50 cetane allowing wilder process in the new diesel hydrotreater. likely to prodmote switch to Thus, a Fischer Tropsch add-on was assumed as appropriate. greenhouse gas green nedw automotive diesel a la Euorpe PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 94 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 9.5 Specialty Product Notes Butadiene and dicyclopentadiene and perhaps isoprene are possibilities of specialty derivative importance and extraction may be economic, although not covered in Steps A + B + C + D. There are several heavier aromatic streams that with R&D&D would appear to offer many prospects for high Alberta value derivatives. The report notes a long, but still incomplete, list of other specialty intermediates available if/as technologies and local markets are developed. 9.6 Balancing Petrochemical Monomer Supply/Demand This study did not start from specific petrochemical monomer demands; rather it worked forward to a basket of monomer for market consideration by others. However, some notes on balancing supply/demand are appropriate. Ethylene Yield Aside from propylene disproportionation, NGL propane could be cracked in an expanded C2 C3 C4 cracker to bring that unit to 1200-KTA (world scale). This added capacity would be available for added SGL feeds and/or arctic gas NGL’s in the future. Propylene Yield Balancing Propylene Ethylene plus Butenes The forward reaction is now commercial (metathesis) and the reverse (disproportionation) is only a reaction change, and another tower, away. A propane to propylene process is well proven (and modelled) but cracking SGL propane to ethylene was assumed preferable for the base case, as the Petro FCC would produce large quantities of propylene and little ethylene. Naphtha “Disposal” The high naphtha yields could/will be challenges and the study identified a variety of processes – old and one just proven – of converting naphtha to propane, isobutane-rich butane and/or aromatics. In practice, it appears that converting naphtha to propane and butane and then cracking the added propane and/or balances/butane in an expanded C2 C3 C4 cracker would be preferable to adding naphtha cracking. The Petro FCC will very likely crack some naphtha (to C3 C4’s) in any case, but lack of data precluded consideration here – other than to assume that would result in even more propylene. Less Xylenes / More Benzenes Xylenes are already being dealkylated to benzene at Scotford and the complex would have such an option, to maximize benzene (reducing para-xylene production). More Aromatics One Edmonton refinery has an ideal fit for high severity catalytic reforming of naphthas. With naphtha from bitumen, conversion could add 50% or more to the Benzene plus p-xylene production shown above. A new process to convert any paraffins in the reformer’s BTX stream to propane and butane, avoiding need for extraction appears attractive. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 95 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Further Integration Another 15,000-+BPD of alkylate potential is The A + B + C + D site including its utilities and service lost in hydrotreating naphthas at Syncrude elements must be planned to add: and Suncor. Processing of unhydrotreated naphthas in the new complex w ould capture this potential. • Derivative Plants to use the new monomers • Added Raw SCO Component (from other bitumen The basic A + B + C scheme enough processors) Hydrotreating hydrogen to hydrogenate over 500,000-BPD of SCO’s (Reduce CO2 emissions from oil • Bitumen Upgrading (to SCO) and more refined sand plants, but offset here as less Fischer products Tropsch liquids would be made.) Capital savings major (especially for new raw 9.7 Clues From Other Complexes Two other complexes may be of special note offering clues to both project corporate structuring, as well as process ideas: (a) Sarnia to Olefins and Aromatics Project – now largely NovaChem’s Corunna flexible feed (C3, C4, naphtha, and light gas oil) ethylene plants partly integrated with Sunoco’s synthetic crude oil and conventional crude refining/aromatic petrochemical operations. (b) BASF/Atofina Port Arthur new 920-KTA ethylene from naphtha, partly Venezuelan hydrotreated SCO derived the related Shell/BASF/Atofina (BASF operated), butadiene and isooctane Sabina project and BASF/Atofina ethylene plus Sabina butylenes to propylene (metathesis) unit. Alberta will always be in competition with the much larger much more complex marine transport available U.S. Gulf Coast chemical industries. Innovative process and project structuring with maximum synergies will be essentially in any new petrochemical monomer/derivative production here. 9.8 Environmental Issues Products • New clean products line needed to Vancouver: • Avoids rail and truck movement of Alberta existing and new transport fuels and components to British Columbia markets. • Opens markets for ideal gasolines and diesels in Alberta and especially British Columbia, with probably alkylate moving as far as California (at the same time) freeing up 90,000- BPD of space for SCO to Washington State refineries. Site Related • Air – Houston area ozone concerns and related petrochemical industry 80% NOX and related VOC reduction needs there, very likely to cascade to selected complex site area, where ozone concern growing and smog evident (from upwind/upriver Edmonton and coal-fired electricity). SO2 control will be equally important. • Water – Water intake minimizing very essential, e.g.: • Fischer Tropsch ideal in this region (to recover process water) • Dow zero discharge approach to be considered • Air Cooling PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 96 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 9.9 Greenhouse Gas Issues Surplus CO ? – While Fischer Tropsch much reduces CO , 2 2 Note need for a major Alberta CO2 pipeline there will still be enough for over 35,000-BPD of new CO2 grid and integrated management system. EOR light/medium crude. Alberta 50% Intensity Reduction – Complex appears very likely to be in accord with CO2 EOR and/or other in-situ CO2 disposal. 9.10 Basic A + B + C + D Yields Table 9.10-1 outlines preliminary estimates of principal product yields from the basic A + B + C configuration, with cases without and with Fischer Tropsch shown. The latter was assumed included in two sensitivity cases: • No heavy gas oil in feed. • Added NGL propane to bring new C2 C3 cracker to a world scale 1,200-KTA of ethylene. Table 9.10-1. Principal Product Yields (KTA/106 SCFD) / [BPCD] / C4 Alkylate [38,800] [38,800] [28,100] [40,300] Naphthas [17,500] [25,400] [20,700] [25,400] Jet/Diesel [28,600] [45,100] [45,100] [45,100] CO2 <21,000> <12,000> <12,000> <12,000> Sulphur <1,160> <1,160> <970> <1,160> * Part or all can be converted to benzene at 70% weight yield. (1) 30,000-BPD from oil sands plants. (2) To raise C2 C3 C4 cracker to world scale 1200-KTA of ethylene. 9.11 Economics The economics are based on WTI at $24.00 U.S., which equates to $35.00 Canadian per barrel for Edmonton par light crude. Natural gas was assumed at all sites at $3.70 Canadian per GJ. A $15.00 Canadian per barrel of delivered in-situ bitumen was only assumed after extensive analysis – it is considered reasonable for advanced low-pressure SAGD in-situ production, on long-term contract basis. The other assumed feedstock prices are to a large extent this study’s judgements, e.g., $25.00 per barrel for heavy gas oils and for NGL butanes. Petrochemical monomer prices were set at $0.03 U.S. per pound under May/June 2002 USGC contract closings for ethylene, propylene and p-xylene as reported by Chemical Week – A USGC benzene value of $1.10 U.S./U.S. gallon less $0.02 U.S. per pound was used – between a May/early July prices. The debit was assumed to permit shipment to the USGC if not used locally. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 97 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Test cases were run at $0.03 per pound below the basic (default) prices – roughly at the oft quoted Alberta advantage level – and then at $0.05 per pound above the basic price, largely due to possibly major increases over time. Gasoline and 50-cetane diesel were assumed at 126% of par crude with alkylate higher at $0.25 Canadian per octane number barrel. Heavy aromatic streams were assumed at fuel gas equivalent – this will be very low sulphur if a fuel oil market is needed in default. Table 9.11-1. Preliminary A + B + C Economic Analyses • With Petrochemical Monomers $0.03 U.S. under USGC unless noted • 29% (2007) Tax Rate unless noted • 25-year Operating Period • 29% CCA • 8% Discount Case IRR % NPV Note (109 Cdn 2002 $) Basic A + B + C 15 5.4 Reference (Basic + Fischer Tropsch) A + B + C + D 15 5.4 New Reference Reference (without HGO) 13 3.4 HGO’s of Value! Reference (with NGL C3) 1,200-KTA Ethylene Cracking @ $22.25 per barrel of propane 15 5.6 - Future Average Price @ $18.00 per barrel 15 6.0 - Summer Price + Storage Fee Product Price Sensitivities Reference Petrochemicals @ $0.06/# under USGC 12 2.9 Reference Petrochemicals @ $0.05 U.S. per pound 18 8.3 - Better Petrochemical Monomer above Forecast needed. Overall capital costs for Reference Case was estimated at $8.5 billion in 2002 Canadian dollars, including incorporation for $0.4 billion for existing Williams SGL facilities. The above data assumed a single A + B + C to project with construction split over two years, rather than the anticipated staged approach. 9.12 Research and Development and Demonstration(R&D&D) • Partial deasphalting in bitumen production would lower downstream capital costs and should be a major target in in-situ production R&D and especially demonstration. • B and C Development Steps need very appreciable pilot plant testing – hydrotreat, Petro FCCU (complete with latter’s recycle and optional naphtha feeds). • Step C needs extensive R&D&D to select the appropriate primary conversion step. • Many options, but no Athabasca bitumen trials, at suitable scale, to date. • Extraction approaches to enhancement of many intermediates – potentially new products themselves – warrants R&D towards reducing overall process costs and improving yields. • Korean catalyst in tube cracking pilot unit might be considered for naphtha and hydrotreated gas oil cracking tests (for long-term planning). • All noted options need piloting and when more than fixed bed reaction needs Alberta demonstration facilities. • Many specialty opportunities, especially in heavy aromatics warrant major R&D. 9.13 Conclusions A highly integrated viable bitumen to high-value-added petrochemicals and premium refined products industry can be developed in Alberta. Appropriate networks – process nodes with feed/product vectors – are needed to match corporate drives of joint effort participants. In addition, many of the key process nodes, as well as those involving high value options will need R&D&D. (The latter may be a special challenge in the case of large-scale processes – such as bitumen conversion and new approaches to ethylene et al from heavy liquid feeds.) PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 98 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 10.0 CONCLUSIONS Table 10-1. Comparison of Study Objectives Study Bases Study Results Goal Add Maximum value to • Integration of oil sands, upgrading, petrochemicals and refinery can provide new Alberta’s Resources ethylene (1,100-KTA), propylene (1,400-KTA) benzene (500-KTA), p-xylene (700- KTA) and incremental naphtha, premium diesel and a major gasoline component Vision Improved Integration of at cost well under USGC. oil sands refining and petrochemicals Feedstocks Assumed in Models • Bitumen 120,000-BPD Resource @$15 per barrel • Heavy Gas Oil 36,000-BPD Upgrading @ $25 per barrel • Syngas Liquids 76,000-BPD Upgrading @ gas replacement value • Plus existing ethylene plant C3+ and H2 and some refinery materials. Siting / Staying Most logical • All near facilities northeast of Edmonton at USGC equivalent costs developed over, say a six-year period. Infrastructure Integration with added • Central Core Utility Complex west coast metals. • New clean products line to Vancouver to open up new markets and allow existing RPP’s to move when new specifications in place. • Variety of other new pipeline connections. Process Assumed in Models • C2C3 Cracking (a) Integration • Heavy Gas Oil Petro FCC - Special high temperature.* • Deep Catalytic Cracking complete with special light crude oil recycle. • C4 Alkylation • Aromatics Complex • Bitumen Conversion – Visbreaking and Hydrotreating • Residue Gasification • Fischer Tropsch Syngas Conversion • Plus auxiliaries and Utilities to match Products Related IRR • Recent USGC on Chemical less freight and about $0.01 per pound marketing Pricing allowance with refined products – 15%. • (Marginal ROI at Alberta Advantage level (12% IRR) Capital • $8.7 billion, but built up in stages. (c) Includes 0.4 for Williams SGL related systems. Environment Tight • Very tight NOX, SO2 controls expected water withdrawal / use critical. Greenhouse 50% under Mta. Avg./ • Should match Alberta goal of 50% reduction / unit product Gas unit product. • With CO2 product goes to CO2 EOR to produce 35,000+BPD of added light crude (no costing/benefits assumed).. Options Comment possibly. • Naphtha can be converted to C3, C4 and/or more aromatics in FCCU or via other routes. • Could add NGL C3 to reach world scale gas cracker, but need summer propane price. • Many options to add processing of other raw SCO’s etc. at new site. • Many specialty chemical options, butadiene, DCPD, and many more to be considered. S R&D&D Support Development • Significant pilot work needed for selected processes. Program • More R&D warranted re improved routes and many new product opportunities. • A semi-commercial scale demonstration center is needed for non-fixed bed process – development / proofing. Table 10.2 continues the study’s assumed inputs and outputs. This has been a preliminary screening study, but should aid in ongoing bitumen to chemicals planning. Notes: (a) C2C3 cracking and Petro FCC appear more economically attractive than liquid feed cracker and bitumen derived HGO’s need significant R&D before it can be considered via conventional cracking. (b) Suitable pyrolysis options not visible, accelerated approvals probably needed to meet schedule. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 99 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Table 10-2. Technical Study Results Feeds Bitumen • Less than 10% of announced new bitumen production 120,000-BPD (in 2010) through 2010. Bitumen Derivative • Light ethylene and heavier Suncor and Syncrude 75,000-BPD (in 2008) hydrocarbons (synthetic gas liquids SGL’s) now burned in fuel gas streams (replaced in fuel gas with natural gas). • Heavy distillates excess to synthetic crude oil (SCO) needs 36,000-BPD (in 2008) from various upgraders. Refinery and Petrochemical • Small propylene and xylene-rich streams (largely from 5,000-BPD Byproducts SCO’s) from refineries. • Existing ethylene plant byproducts (now exported) and 8,000-BPD+ excess hydrogen (now in fuel gas) in exchange for natural 90 x 106 SCFD gas. • Some natural gas liquids (NGL’s) butanes (just enough to 8,000-BPD balance needs of one process). 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 C4 Alkylate • High octane, very environmentally friendly gasoline New 39,000-BPD component (Alberta, British Columbia and California markets). 1 Premium Jet Fuel and • Also very environmentally friendly (Alberta and British New 45,000-BPD Diesels Columbia markets) 1 Other Products Naphthas • Assumed routed to bitumen blending, but with alternates 25,000-BPD noted for conversion to more petrochemicals CO2 • To new CO2 enhanced oil recovery. 30/35,000-BPD (More Alberta light crude) 2 1 Note new clean line to Vancouver needed for marketing these products (and frees up 90,000-BPD of capacity for SCO sales to the Northwest U.S. 2 No value placed on CO2 or added crude production. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 100 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Environmental considerations will be very important and the complex appears likely to achieve the 50% reduction in greenhouse gases per unit of output as desired by Alberta and the gases to diesel unit will minimize water demands, another important Alberta objective. The study notes a wide variety of process options, especially relative to high value-added derivative opportunities. Also, a very sound supporting Research and Development and Demonstration (R&D&D) effort appears essential. The 15% internal rate of return was estimated for such a mega $8 to 9 billion 2002 Canadian complex before optimizing and consideration of rising margins on petrochemicals. Accomplishing such a system integrated – from the bitumen producers through to new Alberta petrochemical derivative plants and new refined product market areas will take very strong effort by industry supported by governments to establish the appropriate partnerships and to quick start staged developments. Note: The trial Venezuelan U.S. very heavy crude to petrochemical project in start-up is appended as an example of how a similar system structured. FIGURE 10.1. NEW VENEZUELAN HEAVY CRUDE TO TEXAS PETROCHEMICAL MONOMER TRAIL Zuata Field Total FinaElf 47% PDVSA 38% o 8.50 API Slat Oil 15% Sincor Upgrader Ship 32o SCO Texas Atofina Port Arthur Refinery Aromatics World’s BASF 60% Newest - Largest Naphtha Atofina 40% Cracker Ethylene * Other C4’s Atofina Polypropylene Propy lene C4’s Other BASF/Shell Poly propylene Products Shell 60% Metathesis BASF 50%? C4 Complex BASF 20% Cut Atofina 50%? Atofina 20% Isooctane (to Gasoline) Butadiene * BASF emphasize “Verbund” total integration of feeds/products into own or joint v enture operations. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 101 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 11.0 RECOMMENDATIONS 11.1 Introduction The Executive Summary above summaries the key business and government activity needs to accomplish significantly more oil sand to petrochemical and refined product production in Alberta. It is recommended that the reader review it again before considering the following recommendations re technical issues in such Alberta economic enhancement. This section does not consider most ongoing improvements in energy efficiency catalysts, process equipment, operation’s control – there will be many and they will have significant impacts on the final bases for design of each step and often more so during operations. The plan as suggested for the various steps were based on availability of feedstocks, suitable product markets or appropriate process bases at time design commences, and on construction labour and materials. The size of the overall complex is such that staged development appears essential, and to a large extent, that matches the rising needs for technology development step to step. New energy efficiency approaches will become available. Even new process equipment can be expected – e.g., divided wall distillation columns and many new membranes and related separation technologies. Here, we only touch on the high points of perceived technical gap filling using a shortened version of NovaChem’s SMART protocols: • Specific Objective Current • Measurable GAP SMART Protocols • Actionable / Agreed Upon * Bridging • Realistic • Timely Future * Future activity. 11.2 Basic Step Activation Here, the basic schemes as set out above are considered technically, assuming all business / government issues resolved and joint actions progressing to startup each stage by the dates noted previously. A Process Significant GAPS Products SGL Recovery SGL Fractionation On stream in C2, C3, C4 Cracking (MAPD Saturation) 2007/2008 Ethylene Propylene Purification (CPP) * Propylene Butadiene Hydrogen (CPP) * C4 Alkylation C4 Alkylation New Process C4 Isomerization * Bracket indicates not major new technology/possible step-out. Note that catalyst selections dependant upon process configurations and decision re whether or not to recover butadiene. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 102 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 (CPP) - Catalyst piloting to insure process objectives. - Piloting in acceptable pilot plant. - Catalyst selected for process design. - Improvement on existing catalyst or new one. - Complete on/before December 2004. New Process - Fixed bed C4 alkylation process. - Piloting and Initial Commercial Operation (by others). - Complete initial Commercial Operation Successfully. - Several Processes by well recognized Licensors at prototype stage. - Complete acceptance by December 2004. B Process Significant GAPS Products HGO Hydrotreat CPP More C2=, C3=, Petro FCC Major Step-out (A) C4 Alkylate On stream in Petro FCC LCO Recycle Major Step-out (B) 2008/2009 Benzene Petro FCC Naphtha New Setting P-Xylene Aromatics Complex Heavy Aromatics Sulphur Recovery Complex CPP - Ongoing Hydrotreating Catalyst Piloting for major Step-out Piloting. Major Step-out (A) & (B) - Define Petro FCC Configuration on Yields. - Build/Operate Pilot Facility – to meld Hydrotreating / Petro FCC / LCO Recycle / Naphtha Cracking tests into Process Design Package. - Pilot - Step-outs of existing / prior refinery processing. Two Licensors. C Process Significant GAPS Products Bitumen Distillation (Conventional) More Naphtha C3=, B, P-X, Conversion Selection / PP / Demo On stream in C4 Alkylate 2009/2010 Gasification PP Heavy Aromatics CO Shift (Conventional) Jet / Diesel Ash Special Tests PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 103 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 Major Conversion Process Selection Optimum S - Primary Bitumen Conversion Process M - Process Selection A - Test Alternate Feed - Piloting & Other Activities to confirm yields and economics of short listed options R - This will be then current or step-out version of an extraction or thermal cracking process (with Licensor support) T - Twelve months of demo-scale testing may be needed. Gasification S - Finalize Design Bases M - Process / Mechanical Design Bases Set A - Bench Test Prospective Feed(s) from above as needed to define process R - Proven process elsewhere T - No undue delays foreseen Ash S - Finalize Disposal / Processing (Note offsite processing likely by experienced operator.) M - Decision made for first five years A - Lab Tests, Piloting R - Novel route unlikely, prior Alberta experience T - Twelve months maximum D Process Significant GAPS Products More Naphtha, On stream in Fischer Tropsch Process Selection 2009/2010 Premium Jet/Diesel (Naphtha Conversion Option) (Piloting, etc.) S - “Select” Appropriate Fischer Tropsch Products and Process M - Licensor Contract A - Analysis of Product Options versus Processes - Piloting of final Conversion Step if appropriate - Licensor Selection Process R - Proven Process today, better tomorrow T - Complete Licensor Selection by early 2006 - Complete Final Catalyst Selection by mid 2007 Each of steps A, B, C and D will require much added desk study and bench testing to insure full integration. Specialties This study did not develop specific specialty product development profiles, as these will need much further study as to source qualities and rates and as to final derivative forms. However, most options noted already have commercial or near commercial parallels. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 104 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 11.3 Complex Siting and Regulatory Bases A key objective from this study should be: S - Select and Provide all Planning / Regulatory Bases for, say, two mega / multiple project sites. M - At least one section on plus designated for integrated bitumen / refining / petrochemical and related infrastructure with all ground rules re access, basic planning and environmental issues, resolved, and outline plan in place. A - Industry / regional developers / government / consulting multi-pronged plan of attack, complete with appropriate actions. R - The report notes several potential sites that may be available or made available. T - The initial site should be ready for discussion with prospective new industry by mid 2003, with earlier decision needs. Decisions Regulatory and specific siting and infrastructure prospective industry should take no more than 5 to 6 months. Note that Neighbour and Municipal Assistance programs will be needed to maximize regional efficiency of such multi-industry sites. Neighbours and residents must also be miners. 11.4 Coordination This study did not see a high degree of understanding of basic processes, industry markets across the bitumen production / upgrading / refining / petrochemical monomer production / derivative production cycle – in industry, government agencies, research organizations and universities. S - A major objective must be to greatly enhance understanding of the key interrelationships, business wise and technically and to enhance the many elements of integration. M - Measuring such a dispersed ongoing objective will be difficult, but setting up a permanent agency to maybe a key initial yardstick, but only outputs from integrated planning and action in all stakeholder sectors will actually measure success. A - A coordinating group of industry, government, research organization, and university managers is strongly suggested with consideration of a permanent (mix) secretariat to coordinate: • Multi-sector Integration Training – business / regulatory / education / research and development. • Multi-sector Integration Studies – leading to specific commercial and R&D projects. R - CONRAD provides an example of such an approach, although only involved on the upstream end. The National Oil Sands Task Force was another, perhaps more forceful, but also time-dated example. T - Such a core organization should be in place by July 2003, but its formative activities will be very important in providing short-term, as well as long-term drives to achieve much more enhanced actual integration and integrative thinking. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 105 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 GLOSSARY 3D 3-dimentional ADOE Alberta Department of Energy AEF Alberta EnviroFuels AEUB Alberta Energy and Utilities Board AIH Alberta’s Industrial Heartland B benzene Bbl barrel BCFD billions of cubic feet BPD barrel per day BTU British Thermal Unit BTX benzene, toluene and xylene C carbon C1 / CH4 methane C2 / C22H6 ethane C2= / C2H4 ethylene C3 / C3H8 propane C3= / C3H6 propylene C3H4 / MAPD methyl acetylene and/or propadiene C4 butanes (i/iso n/normal) C4C6 butadiene C4H8 butyelnes (various) C5 pentanes C5+ pentanes plus (condensate) from natural gas processing C6 hexanes C8 octanes C9 nonames C10 dexanes CANMET Canadian Centre for Mineral and Energy Technology CASA Clear Air Strategy for Alberta CBM coal bed methane CCME Canadian Council of Ministers of the Environment CNRL Canadian Natural Resources Ltd. CO carbon monoxide CO2 carbon dioxide CO2 EOR carbon dioxide enhanced oil recovery COS carbonyl sulphide PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 106 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 DAO deasphalted oil DCF discounted cash flow DME dimethylether DPCD DiCyclopentadiene E1 Joffre Ethylene Unit #1 – NovaChem E2 Joffre Ethylene Unit #2 – NovaChem E3 Joffre Ethylene Unit #3 – Joint NovaChem / Dow EOR end of run FCCU Fluid Catalytic Cracking Unit FGD flue gas desulphurization FT Fischer Tropsch GJ gigajoule H2 hydrogen HF hydrofluoric acid H2O water H2S hydrogen sulphide H2SO4 sulphuric acid HGO heavy gas oil HHV higher heating value HSC high severity cracking HT hydrotreater i/n iso/normal InALK indirect alkylation process (UOP Trademark) IRR internal rate of return kg kilograms KTA kilotonnes per annum kW kilowatt kWh kilowatt per hour LCO light cycle oil (in FCCU) LHV lower heating value LPG liquefied petroleum gas MAPD methyl acetylene/propadiene mb/d 103 barrels per day MSCF million of standard cubic feet MTBE methyl tertiary butyl ethyl MW megawatt (106 watts) MWh megawatt per hour N2 nitrogen PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 107 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 N2O nitrous dioxide naphtha gasoline boiling range hydrocarbon blend NCUT National Centre for Upgrading Technology NGL natural gas liquids NOX nitrogen oxides (NO and NO2 expressed as NO2) o-xylene ortho-xylene PADD Petroleum Administration District for Defense POSM/SMPO co-production of styrene and propylene oxide PSA pressure swing absorption pX para-xylene p-xylene para-xylene RIWG Regional Issues Working Group (Fort McMurray area) ROI return on investment RPP request for proposal S sulphur SOR start of run SCFD standard cubic feet per day SCFM standard cubic feet per minute SO2 sulphur dioxide SAGD steam assisted gravity drainage SGL synthetic gas liquids – C2’s to C4’s from upgraders SMPO co-production of styrene and propylene oxide SOAP Sarnia olefins and aromatics process SRT short residence time syngas synthesis gas – mixture of CO and H2 from gasification TPD tonnes per day TX Texas USGC United States Gulf Coast VCO volatile organic compound VGO vacuum gas oil wt.% weight percentage WTI West Texas Intermediate (crude) PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 108 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 REFERENCES 01-Lippe, Daniel, Petral Worldwide Inc.,”Global Feedstock Pricing: U.S. Gulf Coast Alternatives & Implications”, Prepared for CERI Petrochemicls Conference, June 2002. 02-Private Communication with Marty Dunlop, Suncor, re Sunoco / Nova Chemical Interplays, May 2002. 03-Alperowicz, Natasha, “BASF, Solvay Confirm Plans for H202-Propylene Oxide”, Chemical Week, May 29, 2002. 04-Private Communication with Ed Condrotte, AED, 2002. 05-Private Communication with Len Flint, Lenef, re ADOE, 2002. 06-TransCanada Midstream, “Hydrocarbon Liquids Conservation Project, Volume 1”, April 1999. 07-Private Communication with Brian Sunderland, Syncrude, re Syncrude Light Ends Balance, April 2002. 08-Private Communication with Mike O’Balla, Nova Chemicals, July 29, 2002. 09-Technical Literature, “CW Price Report”, Chemical Week, March 27, 2002. 10-Technical Literature, Stell, Jeannie, Survey Editor, “Ethylene Report”, Oil & Gas Journal, March 11, 2002. 11-Private Commucation, From Robert Vergette, Trans Mountain Pipe Line Company LTD. to Bruce McEwen, Fuels Division, Oil, Gas & Energy Branch Environment Canada, February 20, 2002. 12-Peckham, John, “Alberta Syncrude Upgrade Projects: Good News for ULSD”, Diesel Fuel News, Vol. 6. N. 8, April 15, 2002. 13-Technical Literature, “Exports of Petroleum Products in April 2002”, National Energy Board, April 2002. 14-Private Communication with Derril Stephenson, Vikor, “Economic Feasibility of Horizontal CO2 EOR Projects in Alberta”, Presented to 2002 Climate Change and Greenhouse Gas (GHG) Technology, May 23, 2002. 15-Mitsubishi, Chemicals SR Product Data, From Mitsubishi web site. 16-Technical Literature, “Refining Processes ‘ 96”, Hydrocarbon Processing, November 1996. 17-Houdek, J. Mark, Hemler, Charles L., Pittman, Rusty M., Upson, Larry L., “PetroFCC New Paradigm?”, UOP LLC, 2001. 18-Technical Literature, “Deep Catalytic Cracking”, Hydrocarbon Processing, November 2000. 19-Private Communication with Takashi Ino, Engineering Department, Nippon-Mitsubishi Oil Corporation, re High Severity Fluid Catalytic Cracking (HS-FCC), January 25, 2002. 20-Simbeck, Dale, Dickenson, Ron, SFA Pacific, Inc.”Petrochemical Feedstocks – From Oil Sands”, Project Workshop Presentation, April 11, 2002. 21-Chemical Week, “Egyptian Government Approves Methanol-to-Olefins”, Chemical Week, June 19, 2002. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 109 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 22-Oh, S.H., Scong, K. H., Kim, Y.S., Choi, S., Lim, B.S., Lee, J.H., Woltermann, J. Chu, Y.F.,”Reformate Upgrading to Produce Enriched BTX Using Noble Metal Promoted Zeolite Catalyst”, Zeolyst International. 23-Oh, S.H., Scong, K. H., Kim, Y.S., Choi, S., Lim, B.S., Lee, J.H., Woltermann, J. Chu, Y.F.,”Heavy Aromatics Upgrading Using Noble Metal-Promoted Zeolite Catalyst”, Zeolyst International. 24-Private Communication with Gerry Ertel, Shell Canada/CASA. 25-Private Communication with Roger Bernar, Marsulex. 26-Matar, Sami, Hatch, Lewis F., “Chemistry Of Petrochemical Processes, Second Edition”, Butterworth- Heinemann, 2001. 27-Matar, Sami, Hatch, Lewis F., “From Hydrocarbons To Petrochemicals”, Gulf Publishing, 1981. 28-Private Communication with Curtis Eng, UOP, 2002. 29-Liebner, W., Bach, H., “Propylur-An Upgrade of Olefin-Rich By-Product”, Presented to the 27th Annual, Dewitt & Co. Inc., World Petrochemical Review, March 19-21, 2002. 30-Habibullah, Arif, “Alaska North Slope LNG Project Considers Various CO2 Removal Processes”, Oil & Gas Journal, June 3, 2002. 31-McCann, T.J., Magee, P.H.S., “Typical Heavy Crude and Bitumen Derivative Greenhouse Gas Life Cycles”, for Regional Infrastructure Working Group, December 2001. 32-Chappel, D., “Northern Gas: Williams Petrochemical Feasibility Study”, CERI Kananaskis Petrochemicals Conference 2002. 33-Graham, Dr. Robert, Robinson, DR. Ronald, Gossen Stuart, “EnSyn’s Partial Upgrading Technology”, Presented at May 8, 2002 Canadian Heavy Oil Association Luncheon. 34-Turaga, U.T., Wang, G., MA, X., Song, C., Schobert, H.H., “Influence of Nitrogen on Deep Hydrodesulfurization of 4,6-dimethyldibenzothiophene”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 35-Stockwatch News, “Taylor NGL LP – News Release”, “AltaGas and Taylor Enter JV for Ethane Extraction Plant”, Canjex Publishing Ltd., 2002. 36-Daage, M, McVicker, G.B., Touvelle, M.S., Hudson, C.W., Klein, D.P., Cook, B.R., Chen, J.G., Hantzer, S., Vaughan, D.E.W., Ellis, E.S., “Selective Ring Opening of Naphthenic Molecules”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 37-Yang, H., Wilson, M., Fairbridge, D., Ring, Z., “Hydrogenation and Mild Hydrocracking of Synthetic Crude Distillate by Pt/Mordenite”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 38-Picciotti, M., Technipetrol SpA Rome, “Ethylene Technologies-1: Novel ethylene technologies developing, but steam cracking remains king”, Oil & Gas Journal online, 1997. 39- Picciotti, M., Technipetrol SpA Rome, “New Ethylene Routes Are Available, But Economics Inhibit Their Use”, Oil & Gas Journal, 1997. 40-White, L.S., Lesemann, M., “Sulfur Reduction of Naphtha with Membrane Technology”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 110 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 41-Scott, Alex, “ Reverse-Selective Sieve Could Lower Separation Costs”, Chemical Week, May 8, 2002. 42-Scott, Alex, “LG Develops Catalytic Naphtha Cracking Process”, Chemical Week, May 22, 2002. 43-Ma, X., Sprague, M., Sun, L., Song,C., “Deep Desulfurization of Liquid Hydrocarbons by Selective Adsorption for Fuel Cell Applications”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 44-Sharma, B.K., Bhagat, S.D., Sarowha, S.L.S., “Separation of Petroleum Vacuum Residues and its Physico-Chemical Characterization”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 45-Davis, Mark E., “Ordered Porous Materials for Emerging Applications”, Nature, Vol. 417, June 20, 2002. 46-Private Communication with Dr. Alan Logan, 2002. 47-Labinger, Jay A., Bercaw, John, “Understanding and Exploiting C-H Bond Activation”, Nature, Vol. 417, May 30, 2002. 48-Nero, V.P., DeCanio, S.J., Rappas, A.S., Levy, R.E., Lee, F.,” Oxidative Process for Ultra-Low Sulfur Diesel”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 49-Hangun, Y., Alexandrova, L., Khetan, S., Horwitz, C.P., Cugini, A., Link, D.D., Haward, B., Collins, T.J., “Oxidative Desulfurization of Fuel Through TAML® Activators and Hydrogen Peroxide”, Preprints a Division of Petroleum Chemistry, Inc., American Chemical Society, Volume 47, No. 1, February 2002. 50-Basta, Nick, “Brown & Root, Phillips Collaborate on a More Selective Catalyst for Ethylene Processing”, Hydrocarbon Online, 7/8/1998. 51-Nowak, Siegfried, “New Routes To Low Olefins”, Institute of Chemical Technology, Berlin, Germany. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 111 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003 ACKNOWLEDGEMENTS The study team has received appreciable assistance / comments from the sponsors listed in Section 1.1 and from NovaChem’s M. Oballa. The study team’s key members have been: Tom McCann – Lead and Process Selector Phil Magee – Material Balancing / Modelling Len Flint – NGL’s and General Overview Peter Fink (KemeX) – Lead on Conventional Ethylene Production Ron Dickenson and Dale Simbeck – Residual Gasification and upgrading process comments Jim Sigurdson – Chemical Industry know-how with McCann selecting the inputs of others for this report. The following specialists have provided significant help themselves and from their organization: UOP – C. Eng Criterion – A. Suchanek, D. Rokash, G. Denis Air Products – H. Gunardson Air Liquide – B. Sanelli U. Anand - Sigurdson & Associates The team also owes many thanks to Dr. du Plessis for his coordination and advice. PETROCHEMICALS FROM OIL SANDS McC+A – July 2002 Page 112 CONFIDENTIAL – Not for Distribution before Jan. 1, 2003