Upgraders and Refineries Facts and Stats
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Refining Bitumen: Costs,Benefits and Analysis
Study No. 145 December 2014 CANADIAN ENERGY REFINING BITUMEN: RESEARCH COSTS, BENEFITS AND ANALYSIS INSTITUTE Canadian Energy Research Institute | Relevant • Independent • Objective REFINING BITUMEN: COSTS, BENEFITS AND ANALYSIS Refining Bitumen: Costs, Benefits and Analysis Copyright © Canadian Energy Research Institute, 2014 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute ISBN 1-927037-30-0 Authors: Dinara Millington Rob McWhinney Zoey Walden Acknowledgements: The authors of this report would like to extend their thanks to all CERI staff that provided insightful comments required for the completion of this report, as well as those involved in the production, reviewing, and editing of the material, including but not limited to Allan Fogwill and Megan Murphy CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca December 2014 Printed in Canada Refining Bitumen: Costs, Benefits and Analysis iii Table of Contents LIST OF FIGURES .............................................................................................................. v LIST OF TABLES ................................................................................................................ vii EXECUTIVE SUMMARY ..................................................................................................... ix CHAPTER 1 INTRODUCTION AND BACKGROUND INFORMATION .................................. 1 Introduction ....................................................................................................................... -
Concept Papers for Changes to Rule 9-1 -- Refinery Fuel Gas Sulfur
Draft: 05‐14‐15 Appendix C: Concept Paper for Changes to Rule 9‐1: Refinery Fuel Gas Sulfur Limits Rules to Be Amended or Drafted Regulation of refinery fuel gas (RFG) requires amendments to Air District Regulation 9, Rule 1, Sulfur Dioxide. Goals The goal of this rulemaking is to achieve technically feasible and cost‐effective sulfur dioxide (SO2) emission reductions from RFG systems at Bay Area refineries. Background The lightest components of crude oil separated by a refinery’s atmospheric fractionator are methane and ethane, which are also the primary components of natural gas. At petroleum refineries, these products are not produced in marketable quantities, but are used as fuel in the numerous onsite steam generators and process heaters. When produced at a refinery, this product is called refinery fuel gas (RFG). Pipeline natural gas may be used as a supplemental fuel when needed to enhance the quality of RFG or when there is not enough RFG available. Unlike, pipeline natural gas, refinery fuel gas often contains significant quantities of sulfur that occur naturally in crude oil. When burned, these sulfur compounds are converted to SO2. Process and Source Description RFG can contain between a few hundred and a few thousand parts per million‐volume (ppmv) sulfur in the form of hydrogen sulfide (H2S), carbonyl sulfide (COS), and organic sulfur compounds, such as mercaptans. During combustion, the sulfur in all of these compounds will oxidize to form SO2, which is a criteria air pollutant and a precursor to particulate matter. Scrubbing with an amine or caustic solution can be effective at removing H2S and some acidic sulfur containing compounds, but is generally ineffective at removing nonacidic sulfur compounds. -
Suncor Q3 2020 Investor Relations Supplemental Information Package
SUNCOR ENERGY Investor Information SUPPLEMENTAL Published October 28, 2020 SUNCOR ENERGY Table of Contents 1. Energy Sources 2. Processing, Infrastructure & Logistics 3. Consumer Channels 4. Sustainability 5. Technology Development 6. Integrated Model Calculation 7. Glossary SUNCOR ENERGY 2 SUNCOR ENERGY EnergyAppendix Sources 3 202003- 038 Oil Sands Energy Sources *All values net to Suncor In Situ Mining Firebag Base Plant 215,000 bpd capacity 350,000 bpd capacity Suncor WI 100% Suncor WI 100% 2,603 mmbbls 2P reserves1 1,350 mmbbls 2P reserves1 Note: Millennium and North Steepank Mines do not supply full 350,000 bpd of capacity as significant in-situ volumes are sent through Base Plant MacKay River Syncrude 38,000 bpd capacity Syncrude operated Suncor WI 100% 205,600 bpd net coking capacity 501 mmbbls 2P reserves1 Suncor WI 58.74% 1,217 mmbbls 2P reserves1 Future opportunities Fort Hills ES-SAGD Firebag Expansion Suncor operated Lewis (SU WI 100%) 105,000 bpd net capacity Meadow Creek (SU WI 75%) Suncor WI 54.11% 1,365 mmbbls 2P reserves1 First oil achieved in January 2018 SUNCOR ENERGY 1 See Slide Notes and Advisories. 4 1 Regional synergy opportunities for existing assets Crude logistics Upgrader feedstock optionality from multiple oil sands assets Crude feedstock optionality for Edmonton refinery Supply chain Sparing, warehousing & supply chain management Consolidation of regional contracts (lodging, busing, flights, etc.) Operational optimizations Unplanned outage impact mitigations In Situ Turnaround planning optimization Process -
PUBLICATIONS SPP Briefing Paper
PUBLICATIONS SPP Briefing Paper Volume 11:18 June 2018 THE NORTH WEST REDWATER STURGEON REFINERY: WHAT ARE THE NUMBERS FOR ALBERTA’S INVESTMENT? Brian Livingston SUMMARY Since 2006, the government of Alberta has tried to increase the volume of raw bitumen upgraded and refined in the province. More specifically, the Alberta Petroleum Marketing Commission (APMC) and Canadian Natural Resources Ltd. (CNRL) have entered into agreements with a facility northeast of Edmonton called the North West Redwater (NWR) Sturgeon Refinery. The NWR Sturgeon Refinery is designed to process 79,000 barrels per day (bpd) of feedstock, consisting of 50,000 bpd of bitumen and 29,000 bpd of diluent (referred to as dilbit). The refinery will produce petroleum products consisting of approximately 40,000 bpd of low sulphur diesel, 28,000 bpd of diluent and 13,000 bpd of other lighter petroleum products. It will also be able to capture 1.2 million tonnes per year of carbon dioxide emitted from the refinery’s operations. This captured carbon dioxide will be compressed, put into a pipeline and then injected into an existing oil field in order to achieve increased production of crude oil (referred to as enhanced oil recovery or EOR). It is the first refinery built in Canada since 1984, and the first one in Canada to refine bitumen into petroleum products such as diesel fuel. It differs from the upgrader built in Lloydminster which only upgrades bitumen into synthetic crude oil that requires further refining at a conventional refinery in order to produce petroleum products. This paper gives a description of the structure of this support by APMC and CNRL using a mechanism whereby those two parties agree to enter into tolling agreements to process the diluted bitumen feedstock into refined petroleum products for sale. -
Characteristics of Oil Sands Products
CHARACTERISTICS OF OIL SANDS PRODUCTS Heather D. Dettman Center for Spills in the Environment Oil Sands Products Training Portland, Maine December 4 & 5, 2012 2 Simplified —Oil Sands to Motor“ Value Chain Tailings Pipeline Transport Desalter Extraction Mining Pipeline Terminal Distillation W ater/Solids Primary Upgrading Removal Coking or Residue Performed at Upgraders DiluentAddition Hydrocracking Performed at Refineries In Situ Production Secondary Upgrading May be needed in future Catalytic Processing (Hydrogen) Refining Catalytic Processing (Hydrogen) Gasoline Diesel 3 Pipeline Definitions Transm ission Tailings Pipeline Transport Desalter Extraction Mining Pipeline Terminal Distillation Feeder W ater/Solids Primary Upgrading Removal Coking or Residue Performed at Upgraders DiluentAddition Hydrocracking Gathering Performed at Refineries In Situ Production Secondary Upgrading May be needed in future Catalytic Processing (Hydrogen) http://www.cepa.com /about-pipelines/types-of-pipelines Refining Catalytic Processing (Hydrogen) Gasoline Diesel 4 0hat Is Bitumen? ° Bitumen is the —extra heavy“ crude oil that remains after the biodegradation of oil in Northern Alberta ° Initial boiling point is 204°C/399.2°F ° Approximately 50wt% of the oil boils at temperatures below 524°C/975.2°F ° Biodegradation has resulted in organic acids being left behind in the oil ° Total acid number (TAN) is 3mg KOH/g which corresponds to an organic acid content of 3wt% in the oil ° Organic acid species in bitumen are relatively large molecules with 70wt% boiling -
Secure Fuels from Domestic Resources ______Profiles of Companies Engaged in Domestic Oil Shale and Tar Sands Resource and Technology Development
5th Edition Secure Fuels from Domestic Resources ______________________________________________________________________________ Profiles of Companies Engaged in Domestic Oil Shale and Tar Sands Resource and Technology Development Prepared by INTEK, Inc. For the U.S. Department of Energy • Office of Petroleum Reserves Naval Petroleum and Oil Shale Reserves Fifth Edition: September 2011 Note to Readers Regarding the Revised Edition (September 2011) This report was originally prepared for the U.S. Department of Energy in June 2007. The report and its contents have since been revised and updated to reflect changes and progress that have occurred in the domestic oil shale and tar sands industries since the first release and to include profiles of additional companies engaged in oil shale and tar sands resource and technology development. Each of the companies profiled in the original report has been extended the opportunity to update its profile to reflect progress, current activities and future plans. Acknowledgements This report was prepared by INTEK, Inc. for the U.S. Department of Energy, Office of Petroleum Reserves, Naval Petroleum and Oil Shale Reserves (DOE/NPOSR) as a part of the AOC Petroleum Support Services, LLC (AOC- PSS) Contract Number DE-FE0000175 (Task 30). Mr. Khosrow Biglarbigi of INTEK, Inc. served as the Project Manager. AOC-PSS and INTEK, Inc. wish to acknowledge the efforts of representatives of the companies that provided information, drafted revised or reviewed company profiles, or addressed technical issues associated with their companies, technologies, and project efforts. Special recognition is also due to those who directly performed the work on this report. Mr. Peter M. Crawford, Director at INTEK, Inc., served as the principal author of the report. -
Opportunities in Alberta's Industrial Heartland
OPPORTUNITIES IN ALBERTA’S INDUSTRIAL HEARTLAND Mark Plamondon, P.Eng Executive Director Alberta’s Industrial Heartland Association CANADIAN GLOBAL AFFAIRS INSTITUTE NOVEMBER 1, 2019 www.IndustrialHeartland.com Suite 300, 9940 – 99 Avenue, Fort Saskatchewan, Alberta T8L 4G8 1.888.414.0032 ALBERTA’S INDUSTRIAL HEARTLAND ASSOCIATION Alberta’s Industrial Heartland is guided by a non profit association of municipalities dedicated to sustainable eco-industrial development. Alberta’s Industrial Heartland Association is a collaborative 20-year partnership of five municipalities and three associate members. www.IndustrialHeartland.com Suite 300, 9940 – 99 Avenue, Fort Saskatchewan, Alberta T8L 4G8 1.888.414.0032 WHAT WE DO • Business Case • Transportation Development • Pipeline Corridors • Investor Outreach • Land Use • Investor Awareness & Hosting Business Infrastructure & Development Planning Communications Government & Community Relations Relations • Provincial Advocacy • Education and Awareness • Federal Advocacy • Social Awareness • Municipal Relations • Community Engagement www.IndustrialHeartland.com Suite 300, 9940 – 99 Avenue, Fort Saskatchewan, Alberta T8L 4G8 1.888.414.0032 STRATEGIC STAKEHOLDER PARTNERSHIPS www.IndustrialHeartland.com Suite 300, 9940 – 99 Avenue, Fort Saskatchewan, Alberta T8L 4G8 1.888.414.0032 ALBERTA’S INDUSTRIAL HEARTLAND 582 sq.km We are Canada’s largest hydrocarbon processing centre Local Spending $1.5 billion Annually Jobs 6,000+ direct $40 billion in 25,000+ existing indirect 40+ Industrial Heartland Investment -
Liquefied Petroleum Gas (LPG)
Liquefied Petroleum Gas (LPG) Demand, Supply and Future Perspectives for Sudan Synthesis report of a workshop held in Khartoum, 12-13 December 2010 The workshop was funded by UKaid from the Department for International Development Cover image: © UNAMID / Albert Gonzalez Farran This report is available online at: www.unep.org/sudan Disclaimer The material in this report does not necessarily represent the views of any of the organisations involved in the preparation and hosting of the workshop. It must be noted that some time has passed between the workshop and the dissemination of this report, during which some important changes have taken place, not least of which is the independence of South Sudan, a fact which greatly affects the national energy context. Critically, following the independence, the rate of deforestation in the Republic of Sudan has risen from 0.7% per year to 2.2% per year, making many of the discussions within this document all the more relevant. Whilst not directly affecting the production of LPG, which is largely derived from oil supplies north of the border with South Sudan, the wider context of the economics of the energy sector, and the economy as a whole, have changed. These changes are not reflected in this document. This being said, it is strongly asserted that this document still represents a useful contribution to the energy sector, particularly given its contribution to charting the breadth of perspectives on LPG in the Republic of Sudan. Liquefied Petroleum Gas (LPG) Demand, Supply and Future Perspectives for Sudan Synthesis report of a workshop held in Khartoum, 12-13 December 2010 A joint publication by: Ministry of Environment, Forestry and Physical Development – Sudan, Ministry of Petroleum – Sudan, United Kingdom Department for International Development, United Nations Development Programme and United Nations Environment Programme Table of contents Acronyms and abbreviations . -
CCS: Applications and Opportunities for the Oil and Gas Industry
Brief CCS: Applications and Opportunities for the Oil and Gas Industry Guloren Turan, General Manager, Advocacy and Communications May 2020 Contents 1. Introduction ................................................................................................................................... 2 2. Applications of CCS in the oil and gas industry ............................................................................. 2 3. Conclusion ..................................................................................................................................... 4 Page | 1 1. Introduction Production and consumption of oil and gas currently account for over half of global greenhouse gas emissions associated with energy use1 and so it is imperative that the oil and gas industry reduces its emissions to meet the net-zero ambition. At the same time, the industry has also been the source and catalyst of the leading innovations in clean energy, which includes carbon capture and storage (CCS). Indeed, as oil and gas companies are evolving their business models in the context of the energy transition, CCS has started to feature more prominently in their strategies and investments. CCS is versatile technology that can support the oil and gas industry’s low-carbon transition in several ways. Firstly, CCS is a key enabler of emission reductions in the industries’ operations, whether for compliance reasons, to meet self-imposed performance targets or to benefit from CO2 markets. Secondly, spurred by investor and ESG community sentiment, the industry is looking to reduce the carbon footprint of its products when used in industry, since about 90% of emissions associated with oil and gas come from the ultimate combustion of hydrocarbons – their scope 3 emissions. Finally, CCS can be a driver of new business lines, such as clean power generation and clean hydrogen production. From the perspective of the Paris Agreement, however, the deployment of CCS globally remains off track. -
Facts About Alberta's Oil Sands and Its Industry
Facts about Alberta’s oil sands and its industry CONTENTS Oil Sands Discovery Centre Facts 1 Oil Sands Overview 3 Alberta’s Vast Resource The biggest known oil reserve in the world! 5 Geology Why does Alberta have oil sands? 7 Oil Sands 8 The Basics of Bitumen 10 Oil Sands Pioneers 12 Mighty Mining Machines 15 Cyrus the Bucketwheel Excavator 1303 20 Surface Mining Extraction 22 Upgrading 25 Pipelines 29 Environmental Protection 32 In situ Technology 36 Glossary 40 Oil Sands Projects in the Athabasca Oil Sands 44 Oil Sands Resources 48 OIL SANDS DISCOVERY CENTRE www.oilsandsdiscovery.com OIL SANDS DISCOVERY CENTRE FACTS Official Name Oil Sands Discovery Centre Vision Sharing the Oil Sands Experience Architects Wayne H. Wright Architects Ltd. Owner Government of Alberta Minister The Honourable Lindsay Blackett Minister of Culture and Community Spirit Location 7 hectares, at the corner of MacKenzie Boulevard and Highway 63 in Fort McMurray, Alberta Building Size Approximately 27,000 square feet, or 2,300 square metres Estimated Cost 9 million dollars Construction December 1983 – December 1984 Opening Date September 6, 1985 Updated Exhibit Gallery opened in September 2002 Facilities Dr. Karl A. Clark Exhibit Hall, administrative area, children’s activity/education centre, Robert Fitzsimmons Theatre, mini theatre, gift shop, meeting rooms, reference room, public washrooms, outdoor J. Howard Pew Industrial Equipment Garden, and Cyrus Bucketwheel Exhibit. Staffing Supervisor, Head of Marketing and Programs, Senior Interpreter, two full-time Interpreters, administrative support, receptionists/ cashiers, seasonal interpreters, and volunteers. Associated Projects Bitumount Historic Site Programs Oil Extraction demonstrations, Quest for Energy movie, Paydirt film, Historic Abasand Walking Tour (summer), special events, self-guided tours of the Exhibit Hall. -
Suncor Energy – Annual Report 2005
Suncor05ARcvr 3/8/06 1:33 PM Page 1 SUNCOR ENERGY INC. 2005 ANNUAL REPORT > growing strategically Suncor’s large resource base, growing production capacity and access to the North American energy market are the foundation of an integrated strategy aimed at driving profitable growth, a solid return on capital investment and strong returns for our shareholders. A staged approach to increasing our crude oil production capacity allows Suncor to better manage capital costs and incorporate new ideas and new technologies into our facilities. production 50,000 bpd 110,000 bpd (capacity) resources Third party bitumen 225,000 bpd Mining 260,000 bpd 350,000 bpd 500,000 bpd In-situ 500,000 – 550,000 bpd OUR PLANS TO GROW TO HALF A MILLION BARRELS PER DAY IN 2010 TO 2012* x Tower Natural gas Vacuum 1967 – Upgrader 1 1998 – Expand Upgrader 1, Vacuum Tower Future downstream integrat 2001 – Upgrader 2 Other customers 2005 – Expand Upgrader 2, 2008 – Further Expansion of Upgrader 2 2010-2012 – Upgrader 3 Denver refinery ion Sarnia refinery markets To provide greater North American markets reliability and flexibility to our feedstock supplies, we produce bitumen through our own mining and in-situ recovery technologies, and supplement that supply through innovative third-party agreements. Suncor takes an active role in connecting supply to consumer demand with a diverse portfolio of products, downstream assets and markets. Box 38, 112 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V5 We produce conventional natural Our investments in renewable wind tel: (403) 269-8100 fax: (403) 269-6217 [email protected] www.suncor.com gas as a price hedge against the energy are a key part of Suncor’s cost of energy consumption. -
Unconventional Oil Resources Exploitation: a Review
Acta Montanistica Slovaca Volume 21 (2016), number 3, 247-257 Unconventional oil resources exploitation: A review Šárka Vilamová 1, Marian Piecha 2 and Zden ěk Pavelek 3 Unconventional crude oil sources are geographically extensive and include the tar sands of the Province of Alberta in Canada, the heavy oil belt of the Orinoco region of Venezuela and the oil shales of the United States, Brazil, India and Malagasy. High production costs and low oil prices have hitherto inhibited the inclusion of unconventional oil resources in the world oil resource figures. In the last decade, developing production technologies, coupled with the higher market value of oil, convert large quantities of unconventional oil into an effective resource. From the aspect of quantity and technological and economic recoverability are actually the most important tar sands. Tar sands can be recovered via surface mining or in-situ collection techniques. This is an up-stream part of exploitation process. Again, this is more expensive than lifting conventional petroleum, but for example, Canada's Athabasca (Alberta) Tar Sands is one example of unconventional reserve that can be economically recoverable with the largest surface mining machinery on the waste landscape with important local but also global environmental impacts. The similar technology of up-stream process concerns oil shales. The downstream part process of solid unconventional oil is an energetically difficult process of separation and refining with important increasing of additive carbon production and increasing of final product costs. In the region of Central Europe is estimated the mean volume of 168 million barrels of technically recoverable oil and natural gas liquids situated in Ordovician and Silurian age shales in the Polish- Ukrainian Foredeep basin of Poland.