Study No. 181 June 2019
CANADIAN SUPPLY COSTS AND EMISSION PROFILES OF ENERGY PETROCHEMICAL PRODUCTS IN RESEARCH INSTITUTE SELECTED HUBS
Canadian Energy Research Institute | Relevant • Independent • Objective
Supply Costs and Emission Profiles of Petrochemical i Products in Selected Hubs
SUPPLY COSTS AND EMISSION PROFILES OF PETROCHEMICAL PRODUCTS IN SELECTED HUBS
June 2019 ii Canadian Energy Research Institute
Supply Costs and Emission Profiles of Petrochemical Products in Selected Hubs
Authors: Evar Umeozor Sochi Iwuoha Anna Vypovska
With Contributions from: Mohamed Refaei Madie Zamzadeh Funmilayo Atilola Diane Okenwa
ISBN 1-927037-66-9
Copyright © Canadian Energy Research Institute, 2019 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute
June 2019 Printed in Canada
Front cover photo courtesy of Google images
Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to all CERI staff that provided insightful comments and essential data inputs 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, Dinara Millington, James Brown and Megan Murphy. Contributions from the following reviewers and industry are also appreciated:
• Professor Ian D. Gates, University of Calgary • Alberta Industrial Heartland Association • Dr. Paige M. Morse, Aspen Technology • Chemistry Industry Association of Canada • Pietro Di Zanno, Di Zanno and Associates • Inter Pipeline Limited • Matthew Foss, MFoss Consulting • Resource Diversification Council • Alberta Energy • South Korean Gas
ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE Founded in 1975, the Canadian Energy Research Institute (CERI) is an independent, registered charitable organization specializing in the analysis of energy economics and related environmental policy issues in the energy production, transportation and consumption sectors. Our mission is to provide relevant, independent, and objective economic research of energy and environmental issues to benefit business, government, academia and the public.
For more information about CERI, visit www.ceri.ca
CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: [email protected] Phone: 403-282-1231
June 2019 Supply Costs and Emission Profiles of Petrochemical iii Products in Selected Hubs Table of Contents
LIST OF FIGURES ...... v LIST OF TABLES ...... vii ACRONYMS AND ABBREVIATIONS ...... ix EXECUTIVE SUMMARY ...... xi CHAPTER 1 INTRODUCTION ...... 1 Overview ...... 1 Why and Scope of Study ...... 3 CHAPTER 2 PETROCHEMICAL INDUSTRY OVERVIEW ...... 5 Petrochemical Processes and Technologies ...... 5 Ethylene ...... 5 Propylene ...... 8 Polyethylene ...... 10 Polypropylene ...... 11 Other Olefins Technologies and Vendors ...... 13 Petrochemical Feedstock Sources ...... 13 Feedstocks Supply and Demand ...... 14 Ethane and Propane...... 16 Naphtha ...... 18 Products Supply and Demand ...... 20 Ethylene ...... 20 Propylene ...... 23 Polyethylene ...... 25 Polypropylene ...... 26 CHAPTER 3 GHG EMISSIONS, MITIGATION AND REGULATIONS ...... 29 GHG Emissions from the Petrochemical Industry ...... 29 Mitigation Pathways ...... 30 Greenfield Facilities ...... 32 Brownfield Facilities ...... 32 GHG Emissions and Carbon Regulations ...... 35 Canada ...... 35 Alberta ...... 37 Ontario ...... 37 The United States ...... 38 South Korea ...... 39
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CHAPTER 4 METHODOLOGY ...... 41 Petrochemical Processes Input-Output Modelling ...... 42 Costs and Economic Impact Assessment ...... 43 Supply Cost Model: Components and Method...... 43 General Model Assumptions ...... 44 Capital Requirement ...... 44 Feedstock Prices ...... 44 Labour ...... 44 Location Factors ...... 45 Cost Analysis Framework ...... 47 Target Markets: The United States and China ...... 47 CHAPTER 5 RESULTS ...... 51 Supply Cost Results: PE and PP Supply Cost Framework, Plant Gate ...... 55 Supply Costs Per Feedstock Type and Jurisdiction, Plant Gate ...... 56 Key Supply Cost Components ...... 59 Landed Supply Costs ...... 62 CHAPTER 6 CONCLUSIONS ...... 65 BIBLIOGRAPHY ...... 69 APPENDIX A ECONOMIC MODELLING DATA...... 77 APPENDIX B PROCESS INPUT-OUTPUT DATA ...... 81 APPENDIX C EXISTING FACILITY INVENTORY ...... 83 APPENDIX D FURTHER BREAKDOWN OF RESULTS ...... 89
June 2019 Supply Costs and Emission Profiles of Petrochemical v Products in Selected Hubs List of Figures
E.1 Feedstock Compositions for Steam Cracking and Propane Dehydrogenation Processes ...... xii E.2 Ranges of Process GHG Emissions for Different Process and Feedstock Options ...... xiii E.3 Indicative NCNC Supply Costs per Jurisdiction and Feed Type, Plant Gate ...... xiv E.4 Indicative CTNC Supply Costs per Jurisdiction and Feed Type, Plant Gate ...... xv E.5 Average Supply Cost and GHG Emissions by Process and Feedstock Options ...... xvi E.6 Total Annual GHG Emissions from Petrochemical Hubs ...... xvii 1.1 Petrochemical Processing Stages for Steam Crackers ...... 1 1.2 Relative Gross Margins for Gas and Oil-based Feedstocks...... 3 2.1 Process Diagram of Steam Cracking of Olefins ...... 6 2.2A Process Diagram of Oleflex Technology ...... 9 2.2B Process Diagram of Catofin Technology ...... 9 2.3 Process Diagram of a Solution-phase PE Technology ...... 11 2.4 Process Diagram of a Typical Bulk-phase Reactor Technology ...... 12 2.5 Process Diagram of a Typical Gas-phase Technology ...... 12 2.6 Schematic Value Chain from Feedstock to Petrochemical Building Blocks ...... 14 2.7 Top 10 NGLs Producing Countries, 2017 ...... 15 2.8 US Fourth Quarter 2018 Domestic NGLs Production ...... 15 2.9 Western Canadian Ethane and Propane Production from Gas Plants ...... 16 2.10 Western Canadian NGLs Production Forecast by Commodity ...... 17 2.11 US NGLs Production from Gas Plants, 2018 ...... 17 2.12 US Ethane Production and Consumption ...... 18 2.13 Global Petrochemical Feedstock Supply Growth, 2011-2035 ...... 19 2.14 World Consumption of Ethylene by Country/Region, 2018 ...... 21 2.15 Global Ethylene Annual Demand Growth ...... 22 2.16 Historical and Forecast Global Ethylene Consumption Growth, 2017 ...... 22 2.17 World Ethylene Production by Region ...... 23 2.18 Global Base Chemical Total Capacity Forecast by Market...... 24 2.19 North American Chemical Capacity Forecast ...... 25 2.20 New and Upcoming USGC Ethylene and PE Plants ...... 26 2.21 Polyethylene and Polypropylene Global Trade Flows by Region, 2017 ...... 27 3.1 Expected Contributions of IEA Mitigation Levers to CO2 Emission Reduction by 2050 ...... 32 4.1 Process Diagram of Integrated Processes for Polypropylene and Polyethylene Production using Various Feedstocks ...... 41 4.2 Yields of Products for Various Single Feedstocks to Olefin Steam Cracker ...... 43 4.3 Supply Cost Analysis Framework ...... 47 4.4 Global Base Chemical Capacity Forecast by Region ...... 48 4.5 China Demand-Supply Balance ...... 49 4.6 New PE Capacities by Product, 2017 ...... 49
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5.1 Feedstock Compositions for Steam Cracking and Propane Dehydrogenation Processes ...... 51 5.2 Ranges of Process GHG Emissions for Different Process and Feedstock Options ...... 52 5.3 Effect of Electricity Source on the Average GHG Emissions for Process and Feed Options ...... 54 5.4 Selected Co-product Yields for Various Process and Feedstock Options ...... 55 5.5 Indicative Supply Costs per Cost Analysis Framework, Plant Gate...... 56 5.6 Indicative NCNC Supply Costs per Jurisdiction and Feed Type, Plant Gate ...... 57 5.7 Indicative NCCS Supply Costs per Jurisdiction and Feed Type, Plant Gate ...... 58 5.8 Indicative CTNC Supply Costs per Jurisdiction and Feed Type, Plant Gate ...... 58 5.9 Indicative CTCS Supply Costs per Jurisdiction and Feed Type, Plant Gate ...... 59 5.10 Supply Cost Structure for PE Production at the Four Hubs ...... 60 5.11 Supply Cost Structure for PP Production at the Four Hubs ...... 61 5.12 Shares of Hydrogen and Propylene Co-product Sales for Each Processing Pathway ...... 62 5.13 Average Supply Cost and GHG Emissions by Process and Feedstock Options ...... 63 5.14 Total Annual GHG Emissions from Petrochemical Hubs ...... 64 C.1 Alberta Olefin Cracking Feedstock ...... 87 C.2 Ontario Olefin Cracking Feedstock ...... 87 C.3 USGC Olefin Cracking Feedstock ...... 88 C.4 South Korea Olefin Cracking Feedstock ...... 88 D.1 Indicative Supply Costs by Jurisdiction – NCNC ...... 90 D.2 Indicative Supply Costs by Jurisdiction – NCCS ...... 90 D.3 Indicative Supply Costs by Jurisdiction – CTCS ...... 91 D.4 Indicative Supply Costs by Jurisdiction – CTNC ...... 91
June 2019 Supply Costs and Emission Profiles of Petrochemical vii Products in Selected Hubs List of Tables
E.1 PE and PP Outbound Average Transportation Costs ...... xvi 2.1 Steam Cracker Yields of Petrochemical Feedstocks ...... 7 2.2 US Steam Cracker Investments and Capacities by Feedstock Type ...... 19 2.3 Petrochemical Production Facilities at Three Main South Korean Centres ...... 20 3.1 Intrinsic CO2 Emission Factors for Various Feedstocks ...... 30 3.2 Energy Reduction Potential by Country ...... 31 4.1 Construction Cost Location Factors for NFoiK Petrochemical Plants, 2018 USGC Cost Basis ...... 46 4.2 Construction Cost Location Factors for FoiK Petrochemical Plants, 2018 USGC Cost Basis ...... 46 5.1 PE and PP Outbound Average Transportation Costs ...... 62 A.1 Supply Cost Model Input Parameters and Assumptions ...... 77 A.2 Indicative SCM Results for Alberta and Ontario Petrochemical Facilities at Plant Gate...... 79 A.3 Indicative SCM Results for USGC and South Korea Petrochemical Plants ...... 80 A.4 Current and Anticipated Jurisdictional Carbon Tax ...... 80 B.1 Sample Steam Cracking Feedstocks, Side- and Co-products, Energy Use and Emissions Data ...... 81 B.2 Naphtha Steam Cracker Yields ...... 81 B.3 Primary and Final Energy Requirements of Petrochemical Processes ...... 82 C.1 Petrochemical Facilities in Alberta, Ontario, USGC and South Korea ...... 83 D.1 Lower Range of Outbound Transportation Costs for PE and PP ...... 89 D.2 Upper Range of Outbound Transportation Costs for PE and PP ...... 89
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June 2019 Supply Costs and Emission Profiles of Petrochemical ix Products in Selected Hubs Acronyms and Abbreviations
Alberta (AB) Alberta Industrial Heartland BACT Best Available Control Technology BPT Best Practice Technology CAF Cost Analysis Framework CAGR Cumulative Annual Growth Rate CAPEX Capital Expenditure CCS Carbon Capture and Storage CERI Canadian Energy Research Institute
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent (including all greenhouse gases) CTCS Carbon Tax, with Co-product sales CTNC Carbon Tax, No Co-product sales ECCC Environment and Climate Change Canada EIA Energy Information Administration (US) EPA Environmental Protection Agency (US) EJ Exajoule ETS Emissions Trading System FCC Fluid Catalytic Cracking FoiK First of its Kind GHG Greenhouse Gas GHGRP Greenhouse Gas Reporting Program GWP Global Warming Potential HDPE High-Density Polyethylene IEA International Energy Agency IPCC Intergovernmental Panel on Climate Change kT Kilotonnes
KT CO2e Kilotonnes of carbon dioxide equivalent kT/yr Kilotonnes per year LDAR Leak Detection and Repair
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LDPE Low-Density Polyethylene LLDPE Linear Low-Density Polyethylene LPG Liquified Petroleum Gas Mbpd Million barrels per day MBTU Million British Thermal Units m3 Cubic meters Mt Million tonnes MTO Methanol-to-Olefins MTP Methanol-to-Propylene Mtpa Million tonnes per annum (Million tonnes per year)
Mt CO2e Million tonnes of carbon dioxide equivalent NCF Net Cash Flow NCCS No Carbon Tax, with Co-product sales NCNC No Carbon Tax, No Co-product sales NGCC Natural Gas Combined Cycle NGL Natural Gas Liquid NRCan Natural Resources Canada OBPS Output-Based Pricing System ON Ontario OPEX Operating Expenditure PDH Propane Dehydrogenation PE Polyethylene PP Polypropylene SC Steam Cracking SCM Supply Cost Model SFC Shipping/Freight Cost STAR Steam Active Reforming TJ Terajoule tpy Tonnes per year US The United States USGC United States Gulf Coast
June 2019 Supply Costs and Emission Profiles of Petrochemical xi Products in Selected Hubs Executive Summary
CERI commissioned this study to quantify greenhouse gas (GHG) emissions from petrochemical processes and evaluate supply costs of products from various processing pathways and petrochemical hubs. The hubs assessed are Alberta Industrial Heartland in Alberta, Sarnia/Corunna (Ontario), the United States Gulf Coast (USGC), and South Korean hubs. Environmental impact is evaluated in terms of carbon dioxide, methane and nitrous oxide emissions from the petrochemical sector. The economic impact is assessed through indicative product supply costs at both the plant gate and at potential destination markets. The United States and China are considered destination markets.
To achieve the objectives of the study, CERI adopted a hub-level analysis approach. We modelled hypothetical integrated petrochemical facilities in each of the hubs, observing jurisdictional differences in the supply cost model and considering various processing pathways for single and mixed feedstocks. Figure E.1 shows the feedstock options speculatively treated in each of the hubs to produce polyethylene (PE via steam cracking1) and polypropylene (PP via propane dehydrogenation2) as the primary/main products for which the supply costs are computed.
1 Denoted in the figure and subsequently as SC 2 Denoted in the figure and subsequently as PDH
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Figure E.1: Feedstock Compositions for Steam Cracking and Propane Dehydrogenation Processes
Ethane Propane Butane Naphtha
100%
90%
80%
70%
60%
50%
40% Feedstock Blend Feedstock 30%
20%
10%
0% SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Process Type CERI also quantified co-products from each processing pathway and ran four supply cost scenarios to capture jurisdictional variabilities, carbon tax and the ability to obtain additional revenues from sales of co-products. The feedstock and process combinations (per Figure E.1), in addition to their integrated polymerization units, constitute the five hypothetical facilities assessed for each of the four hubs of focus in our product supply cost modelling.
Emission intensities of processing pathways capture the differences in processing technologies, fuel types, electricity requirements and sources. Figure E.2 shows the ranges of GHG emissions for each process and feedstock combination. Natural gas combined cycle (NGCC), coal and cogen are the three types of electricity sources incorporated in our current modelling, however, NGCC is used as the benchmark electricity source for most facilities. The process emissions include those from the production of olefin monomers and the subsequent polymerization step. Process emissions are expressed in per tonne of the main product.
June 2019 Supply Costs and Emission Profiles of Petrochemical xiii Products in Selected Hubs
Figure E.2: Ranges of Process GHG Emissions for Different Process and Feedstock Options
2.00
1.80
1.60
1.40
product)
- e/t
2 1.20
CO - 1.00
0.80
0.60
0.40 Process Emissions (t Emissions Process
0.20
0.00 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Process and Feedstock Options
The PDH process for on-purpose polypropylene has the lowest GHG emission intensity ranging between 0.19-0.62 t-CO2e/t. Polyethylene from ethane cracking plants has the next lowest intensity ranging from 0.54 to 1.35 t-CO2e/t. Polyethylene from naphtha cracking has the highest GHG intensity ranging between 1.24 to 1.96 t-CO2e/t. However, naphtha cracking has a wider product spread relative to the other cracking feedstocks. Therefore, if overall emissions were to be allocated to all high-value products using any of the standard life cycle analysis (LCA) methods (such as system expansion, substitution or partitioning), the intensities based on each high-value chemical would be lower. Nevertheless, our approach in this study is to quantify total processing emissions based on the main product for each feedstock processing pathway.
The primary sources of GHG emissions in a petrochemical plant are process heaters, boilers, cooling towers, catalyst regeneration vents, gas purge/flare systems, MSS (maintenance, start- up and shutdown) emissions, and process fugitives. Based on EPA prevention of significant deterioration (PSD) filings, fugitive emissions may account for up to 5% of total facility GHG emissions (Trinity Consultants 2012, 2012; US EPA 2014; Chevron Phillips 2018; US EPA 2012; Environmental Resources Management 2014). Depending on the process and technology in use, methane and nitrous oxide emissions account for between 0.1% to about 2% of total carbon dioxide equivalent (CO2e) emissions.
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Figures E.3 and E.4 show two supply cost assessment scenarios where a carbon tax is either excluded (NCNC) or included (CTNC) without considering the sales of co-products in both cases in the model. The NCNC scenario captures the jurisdictional impacts of constructing and operating the petrochemical facilities in Alberta, Ontario, USGC, and South Korea. Polyethylene and polypropylene average plant gate supply costs for all hubs in NCNC are $1,881/t and $1,772/t, whereas in CTNC they are $1,918/t and $1,811/t, respectively. The indicative supply costs are higher when the carbon tax is included in the model. However, other variables such as feedstock costs and co-product sales revenue have bigger effects on costs compared to a carbon tax.
Figure E.3: Indicative NCNC Supply Costs per Jurisdiction and Feed Type, Plant Gate (2018 Constant Dollars)
4500 4000 3500 3000 2500 2000
1500 Supply cost ($/t) cost Supply 1000 500 0 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
AB ON USGC South Korea
June 2019 Supply Costs and Emission Profiles of Petrochemical xv Products in Selected Hubs
Figure E.4: Indicative CTNC Supply Costs per Jurisdiction and Feed Type, Plant Gate (2018 Constant Dollars)
4500 4000 3500 3000 2500 2000 1500
Supply cost ($/t) cost Supply 1000 500 0 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
AB ON USGC South Korea
Overall, a carbon tax has the most impact on Canadian supply costs despite the predominant processing of the lower GHG-intensity gas-based feedstocks in Canadian petrochemical hubs. Thus, this stems from the higher price of CO2e emissions in Canada, compared to the other jurisdictions. CERI also assessed two other scenarios with the carbon tax and co-product revenue (CTCS), and no carbon tax with co-product revenue (NCCS). This is discussed further in Chapter 5.
The availability of cheaper NGL feedstocks in producing areas such as Alberta and the USGC results in lower PE supply costs for ethane and ethane+propane cracking plants. In the absence of a carbon tax, PP supply costs at Canadian and USGC facility gates are quite similar – albeit, slightly higher for USGC plants but more pronounced for a South Korean plant due to feedstock cost.
Landed supply costs provide a perspective of the indicative supply costs at the destination market for produced PE and PP using the five feed options and transported to the USGC or China for sales. The shipping/freight cost (SFC) is added to the supply costs obtained for each of the assessment scenarios to obtain the supply cost at the destination market. CERI’s SFC estimates were based on information available in the public domain, as well as feedback from CERI interviews with petrochemical industry experts. Table E.1 shows the base case shipping/freight costs (SFC) for transporting PE and PP from the four petrochemical hubs studied by CERI to the USGC and China. CERI’s base case SFC is based on the average between the low and high SFC (shown in Appendix A). Canadian hubs have the advantage to ship to China against USGC, and the advantage to shipping products to the USGC against South Korea.
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Table E.1: PE and PP Outbound Average Transportation Costs
USGC (Texas) China PE PP PE PP Origin $/t $/lb $/t $/lb $/t $/lb $/t $/lb Alberta 13 0.006 18 0.008 23 0.010 28 0.013 Ontario 14 0.006 19 0.009 26 0.012 30 0.014 USGC 8 0.003 11 0.005 31 0.014 35 0.016 South 26 0.012 29 0.013 18 0.008 22 0.010 Korea
If one takes the average supply cost across all the hubs, for each process and feedstock option under the NCNC scenario, the economic and environmental performance indicators of each feedstock processing pathway can be visualized and compared – as in Figure E.5 – with reduced effects of jurisdictional differences on the cost for each process and feedstock combination.
Processes using gas-based feedstocks have lower emissions and supply costs as against LPG and naphtha, which have higher energy requirements. For the PE and PP production studied here, steam cracking of ethane feed and propane dehydrogenation have the lowest economic and GHG emission intensities relative to the other production pathways.
Figure E.5: Average Supply Cost and GHG Emissions by Process and Feedstock Options
June 2019 Supply Costs and Emission Profiles of Petrochemical xvii Products in Selected Hubs
Considering the compositions of processing capacities in the four petrochemical hubs studied here, CERI can estimate their total annual GHG emissions at defined utilization levels. In consonance with our supply cost modelling assumption, we apply a 90% capacity utilization factor to the most recently available data on processing capacities at the hubs as reported by (Koottungal 2015) and (Morse 2017). By combining the ranges of emission intensities of each processing pathway with the total products generated therein, CERI evaluated total annual emissions in each hub, as shown in Figure E.6.
Figure E.6: Total Annual GHG Emissions from Petrochemical Hubs (2016 capacities basis)
US GC
S.Korea
ON
AB
0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000
Total Annual GHG emissions (kt-CO2e)
Total annual GHG emissions are highest for the USGC, in the range of 19.8 Mt CO2e to 37.4 Mt CO2e. Seconded by South Korean hubs with emissions ranging between 6.0 Mt CO2e and 9.5 Mt CO2e. Canadian petrochemical hubs have the lowest annual GHG emissions with the Ontario hub emitting between 0.5 Mt CO2e to 0.9 Mt CO2e, whereas the Alberta hub emits between 2.1 Mt CO2e to 5.2 Mt CO2e.
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June 2019 Supply Costs and Emission Profiles of Petrochemical 1 Products in Selected Hubs Chapter 1: Introduction
Overview The petrochemical industry is a major contributor to global industrial energy demand and the – usually – consequent greenhouse gas emissions (Griffin, Hammond, and Norman 2018). It is the highest industrial consumer of energy; accounting for about 42.5 exajoules (EJ) in 2014 of final energy consumption as feedstock and process fuel. Emissions from the petrochemical and chemicals sector represent around 7% of global man-made greenhouse gases (GHG) and 5.5% of the CO2 emissions (Levi and Cullen 2018). There are three primary GHG emissions from petrochemical facilities: carbon dioxide, methane, and nitrous oxide. Sources of emissions can also be categorized into process chemistry, heating, and electricity requirements. Direct emissions are typically from the process chemistry and heating whereas indirect emissions usually arise from electricity usage. Overall, energy requirements are satisfied with fuel combustion of dedicated fuel feedstocks and/or processing of by-product gases.
Generally, petrochemical plants break down (or crack) oil or gas-based hydrocarbon feedstocks at high pressure and temperature into simpler chemical building blocks. Thermal processes such as steam cracking are central to petrochemicals manufacture where steam and heat are used to breakdown heavier hydrocarbons into lighter olefins (or alkenes) and aromatics, also called high- value chemicals, using oil or gas-based feedstocks. Oil-based feedstocks are usually naphtha and gas oil. Gas-based feedstocks include natural gas, liquified petroleum gases (LPGs) and natural gas liquids (NGLs) from which methane, ethane, propane, butane, and pentanes can be obtained. An assembly of such simpler chemicals constitute the derivatives (or polymers) used to create various plastic products.
Steam crackers are usually designed with the flexibility to take feedstocks of various oil or gas- based hydrocarbons. Figure 1.1 shows a simplified process diagram of a steam cracker. The feedstock and steam mixture is sent into a furnace where the cracking reaction occurs. The products are quenched (cooled quickly) to avoid the further formation of undesired products, then compressed, refrigerated and separated into its various components of interest in a fractionator.
Figure 1.1: Petrochemical Processing Stages for Steam Crackers
Source: (Benchaita 2013)
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Most steam crackers in areas where natural gas (and NGLs) are not in abundance have historically used oil-based feedstocks. But this has started to change as more export quantity NGLs are available from unconventional sources (like shale or tight reservoirs).
The growth of production from liquids-rich shale and tight formations guarantees relatively cheaper petrochemical feedstocks from NGLs, as against oil-based feedstocks. Historically, the prices of crude oil and natural gas were correlated until around 2009-2010 when they decoupled, and the price of gas has remained relatively cheaper (Morse 2017). Prices of NGL components such as ethane, propane and butane have also either decoupled from a similar relationship with oil price or are expected to do so in the near future as logistical constraints are resolved and market access improves (Morse 2017). However, olefin prices have remained correlated with crude oil prices – at least, currently – maintaining the impetus for gas-based feedstocks to stay more economically competitive so long as crude oil remains more expensive than the abundant natural gas (Morse 2017; Fattouh and Brown 2014).
Petrochemical plants can be built on-purpose where the plants take specific feedstocks for conversion to the desired product(s), particularly in areas where the desired feedstock is available. Moreover, petrochemical plants are often integrated with crude oil refineries, where some of the refinery products (like naphtha and gas oils) are used as feedstocks for the plant. Some of the desired petrochemical products are also generated as side products from crude oil refining operations.
When the supply of a petrochemical product is inadequate (either when sourced as a side- product from refining or co-product from steam cracking), on-purpose plants can be built to augment the supply. Among other factors, the type of feedstock used for a petrochemical process affects the product variety and yields. Oil-based feedstocks for steam crackers tend to have a wider range of products (or co-products) but lower yields of high-value chemicals than gas- derived (NGL-based) feedstocks. For instance, typical ethylene yields from gas and liquid feedstocks have been reported to be around 80% and 30%, respectively (Fattouh and Brown 2014).
Depending on the domestic dry natural gas (for heating, etc.) and NGL (for petrochemicals) market pricing and fluctuations, gas processing operations can be tuned to increase or reduce the recovery of ethane and other NGL components from dry natural gas (Fattouh and Brown 2014). This allows operators to capitalize on any spread between natural gas and NGL prices if there is access to the market for the NGL products. Between 80% to 90% of ethane is typically recoverable from the raw gas stream. Facilities operating in ethane “rejection” mode (due to lack of or inadequate transport infrastructure or when the ethane price is too low) will remove just enough ethane in the dry gas stream in order to meet pipeline specifications (Fattouh and Brown 2014). Figure 1.2 compares gross margins for gas and oil-based feedstocks for olefins production. As indicated, even with the low crude oil prices in 2014, oil-based feedstocks processing still resulted in gross margin loss of about 40% relative to gas-based feedstocks.
June 2019 Supply Costs and Emission Profiles of Petrochemical 3 Products in Selected Hubs
Figure 1.2: Relative Gross Margins for Gas and Oil-based Feedstocks
Source: (Fattouh and Brown 2014)
In North America, as the abundance of natural gas (and NGLs) from shale and tight resources in the United States and Canada depresses natural gas prices and the value of its constituent hydrocarbons, many petrochemical producers are switching to gas-based feedstocks. Producers in such areas with cheap and stable gas availability see better economic incentives to move from oil-based feedstocks to gas-based ones. However, gas-based feedstocks, such as ethane or liquified petroleum gas (LPG), have lower yields of co-products – particularly with respect to propylene production, even though there is a growing demand for it and its derivatives in North America and elsewhere. This drives interest to build new on-purpose propylene production plants in Canada to support growing demands and rising demand opportunities in the US and other areas. To this end, some petrochemical projects have been proposed in Canada1 to take advantage of these current opportunities and to further diversify the use of natural resources through new value-added production.
Why and Scope of Study Petrochemicals are known to be the primary route for diversifying oil and gas commodities- dependent economies such that more economic value can be extracted from natural resources. In Canada, Alberta is the dominant producer of oil and gas and hosts one of the three major petrochemical hubs in the nation at the Alberta Industrial Heartland. The other two hubs (Corunna and Sarnia) are in Ontario.
Recently, Alberta embarked on a government-led diversification effort by providing $2.1 billion worth of incentives to further drive petrochemicals capacity investments in the province; based on an abundance of cheap NGL feedstocks. At the same time, the Canadian federal government, along with some provincial governments, has instituted carbon taxation on several industrial
1 These projects include Inter Pipeline’s 525 kilotonnes per year (ktpa) propane dehydrogenation (PDH) facility in Strathcona County, Alberta and the joint venture Pembina Pipeline Corporation and Canada Kuwait Petrochemical Corporation 550 ktpa PDH facility in Sturgeon County, Alberta.
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activities that contribute to the emission of greenhouse gases. It is anticipated that international trade in petrochemical products will have some form of emissions consideration in the future. Some stakeholders have indicated that carbon taxation would likely affect the competitiveness of Canada’s existing and future petrochemical developments, particularly with regards to the global competitiveness of Canada’s petrochemical products in the US and the Asia-Pacific markets where export opportunities exist.
Under these prevailing circumstances, this study aims to evaluate the GHG emissions and supply costs of the predominant petrochemicals production pathways in Canadian, US, and Asia-Pacific petrochemical hubs. The primary focus is on processes and technologies for ethylene, propylene, polyethylene, and polypropylene production using various single feedstocks and mixed- feedstocks including ethane, propane, LPG, and naphtha. Feedstock blends are chosen to reflect mixed-feedstock flows into petrochemical hubs where such are typically processed – as reported in the literature (Koottungal 2015). GHG emissions to be addressed are restricted to carbon dioxide, methane and nitrous oxide. The process emissions and product supply costs are compared within and across the jurisdictions particularly for the petrochemical hubs in Alberta, Ontario, US Gulf Coast, and South Korea. In assessing emission footprints of the production pathways, CERI examined the potential process and technological opportunities to improve performances of existing and new production facilities. By incorporating the cost of carbon in each of the jurisdictions, CERI assessed the impact of GHG emissions regulations on the supply cost of the products at both plant gate and the potential market destinations.
Report Structure Chapter 2 provides an overview of the industry, focusing on the various petrochemical processes, technologies, feedstocks, products, and markets that are of interest in this study. Chapter 3 identifies sources of greenhouse gas emissions and potential mitigation pathways to improve the environmental performance of the sector. Our methodologies for quantifying feedstock requirements of various petrochemical processing pathways, the products, process GHG emissions, and the supply costs of products from various petrochemical hubs are presented in Chapter 4. Presenting both the process and economic modelling techniques facilitates the discussion on the effects of technical decisions on costs. Chapters 5 and 6 discuss the results and overall conclusions from the analyses.
June 2019 Supply Costs and Emission Profiles of Petrochemical 5 Products in Selected Hubs Chapter 2: Petrochemical Industry Overview
In 2018, CERI published Study No. 169 (CERI 2018a), which investigated the processes and economic impacts of methane to derivatives petrochemical subsector. This study builds on the existing studies by considering petrochemical feedstocks other than methane (or natural gas).
Petrochemical Processes and Technologies Ethylene Ethylene is the predominant petrochemical for producing various derivatives and end-use products. The three major chemical processes for ethylene production are:
• Steam cracking of oil and gas-based feedstocks • Dehydration of ethanol • Methanol-to-Olefins
Although steam cracking of oil-based feedstocks generates more co-products, it offers relatively lower ethylene yields compared to cracking of gas-based feedstocks.1 With the abundance of unconventional gas in Canada, gas-based feedstocks are the focus of ongoing and future petrochemicals development projects. The availability and lower cost of gas feedstocks also make gas (and NGLs) feedstocks more desirable for the petrochemical sector in other North American hubs that are beneficiaries of processed gas supplies from prolific onshore shale and tight gas fields. As most North American ethylene producers transition to steam cracking of gas feedstocks, fewer co-products (mainly propylene) are generated overall which depresses the supply of such products despite the current and growing demand.2 Therefore, on-purpose propylene production3 plants are expected in many hubs4 to address the market gap.
Steam cracking of ethane and/or propane for ethylene production has three essential operations: cracking reaction and quenching, product compression and drying, and separation of products and co-products. The quench is needed to stop further reactions that form undesired products after the steam cracking. Figure 2.1 shows a simplified process diagram of an ethane- propane cracking for ethylene production. Actual commercial technologies for steam cracking might differ in design according to each vendor but the basic processing principles are generally the same.
1 See Table 2.1. A complementary schematic comparison of the petrochemical yields from various feedstocks is also later presented in Chapter 4 of this report. 2 Propylene demand growth is presented in the “Products Supply and Demand” section of this report. 3 A discussion on on-purpose propylene production is provided in (Fielden 2013) 4 See (Fielden 2014)
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Ethylene production is a non-catalytic, high-temperature process relying on cracking saturated hydrocarbons into olefins. In the process, the feedstock is mixed with steam and then thermally cracked into ethylene and co-products in a furnace at temperatures of 750oC to 875oC, depending on the feedstock. The change occurring during the reaction is mainly dehydrogenation of the feedstock achieved within a short residence time (less than one second) to maintain the desired product yields and avoid undesired products. The presence of steam in the reaction is important for good product yields and elimination of coking deposits on reactor walls which limits the efficiency of the process. Consequently, carbon dioxide, carbon monoxide, and hydrogen are also generated.
Figure 2.1: Process Diagram of Steam Cracking of Olefins
Source: (Siemens 2013)
The effluent of the cracker must be cooled immediately (quenched) to avoid further reactions that lead to loss of product quality. Water or oil can be used for the cooling and heat recovery for other uses. Subsequently, gaseous products are separated from heavier products, dried, purified and compressed. Heavier products are condensed and fractionated into the various components. Unconverted products are recycled back to the cracking furnace. Some of the co- products, such as hydrogen, are used to fuel the furnace and maintain the process. Co-products may also be purified and sold as high-value chemicals within adjacent processes in any of the petrochemical hubs. Processing gaseous mixtures of light end hydrocarbons has the characteristic of producing mainly ethylene and propylene, whereas processing liquid feedstocks coproduces propylene and aromatics. Table 2.1 shows the typical product yields of various feedstocks.
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Table 2.1: Steam Cracker Yields of Petrochemical Feedstocks (%)
Yield by Weight Ethane Propane Butane Naphtha Gasoil Hydrogen and methane 13 28 24 26 18 Ethylene 80 45 37 30 25 Propylene 2 15 18 13 14 Butadiene 1 2 2 5 5 Mixed butenes 2 1 6 8 6 C5+ 2 9 13 8 7 Benzene 0 0 0 5 5 Toluene 0 0 0 4 3 Fuel Oil 0 0 0 2 18 Source: (Fattouh and Brown 2014)
Ethanol dehydration is considered a process for environmentally cleaner production of ethylene using bio-ethanol. Although ethanol from any source could be used, the primary goal is non- petroleum-based manufacture of ethylene. Global efforts to improve sustainability and mitigate global warming drives the interest to develop renewable ethylene production pathways. Ethanol dehydration is an endothermic process with better yields at higher temperatures and pressures – typically around 250oC and 20 bar. This method of producing ethylene has relatively higher costs than the conventional steam cracking method. BP Chemicals Technology and Chematur Technology have developed commercially available ethanol to ethylene processes. One limitation of the technology is that there needs to be enough ethanol production, so it is more suitable to countries with large ethanol production such as Brazil and the US. Also, from a life cycle perspective, the environmental benefits of such processes are still subject to debate. If the scope of impact assessments were to cover the cultivation stages, overall cycle emissions balance would depend on the type of agricultural feedstocks, land-use change, energy inputs and source intensities. There are also concerns about the impact on food availability and water use.
Methanol-to-Olefins (MTO) process is another alternative route to ethylene production using methanol feedstock which can be sourced from various raw materials such as natural gas, biomass or coal. At the moment, commercial coal-to-olefins (CTO) plants are mostly in China and South Africa. Coal units require larger capital outlays and are usually integrated to polymer close to the coal mine, to ease transportation of final products to markets (Morse 2017). As of 2015, MTO and CTO represented about 4% of global ethylene production capacity and is expected to reach 15% by 2022 (Jones et al. 2016; Morse 2017). Aside from their high capital costs, CTO developments also raise more environmental concerns.
MTO technologies have been developed by vendors such as Norsk A/S and UOP LLC (Intratec 2019). MTO can also be used to produce propylene (methanol-to-propylene, MTP). Lurgi MTP is a commercial technology that produces polymer-grade propylene and ethylene, along with blending stock gasoline and LPG co-products (Air Liquide 2017). A detailed discussion of the MTO process is available in CERI Study No. 169 (CERI 2018a).
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Propylene Propylene is produced either as a co-product or on-purpose (as earlier indicated). The sources of propylene as a co-product (or by-product) are the steam cracking of naphtha,5 LPG, or from fluid catalytic cracking (FCC) units in refineries (ICIS 2010). Cracking severity and feedstock blend alterations can be used to improve propylene yields relative to ethylene in steam crackers to between 25-45%, whereas catalyst performance enhancements are used to improve propylene production from refinery FCC units.
Due to the existing and future demand growth for propylene,6 on-purpose technologies and projects are being developed and sanctioned to primarily produce propylene using processes such as propane dehydrogenation (PDH), methanol-to-propylene (MTP) and metathesis (ICIS 2010).
Propane dehydrogenation (PDH) is the primary, direct, commercial route to convert propane to propylene but it requires a low-cost supply of the feedstock for economic viability. It is a high- temperature process occurring at 500-700oC in the presence of a catalyst. In comparison to propylene generation as co-product from crackers, the PDH process entails separate capital investment for the on-purpose propylene and is, therefore, considered more capital-intensive. Thus, process innovations have targeted a reduction in capital and operating costs.
PDH is an endothermic process that offers very high propylene yields of around 90% (Intratec 2019). Several PDH technologies have been developed such as:
• Oleflex by UOP • Catofin by CB&I Lummus • STAR by Uhde GmbH
The Oleflex process technology can be described in terms of the major operations such as the reaction and product recovery steps. The propylene yield is enhanced by higher temperatures and lower pressures using a moving-bed system for continuous catalyst circulation and regeneration. Typical operating conditions are about 650oC at about atmospheric pressure, with propylene yields of up to 90% (wt.). The new PDH plants to be built in Alberta by Inter Pipeline7 and Pembina8 have selected this technology. Figure 2.2A shows a sample flow diagram of the Oleflex process design.
5 A complementary discussion on steam cracking of naphtha is provided in the “Petrochemical Feedstock Sources” section of this report. 6 Propylene demand growth is presented in the “Products Supply and Demand” section of this report. 7 See (Inter Pipeline 2019) 8 See (Pembina Pipeline Corporation 2019)
June 2019 Supply Costs and Emission Profiles of Petrochemical 9 Products in Selected Hubs
Figure 2.2A: Process Diagram of Oleflex Technology
Source: CERI
Catofin technology is another dehydrogenation-based propylene production design. It uses fixed- bed reactors, with at least two of them to alternate between online and offline operating states to enable catalyst regeneration. The two primary steps in the process include reaction and regeneration and recovery of products. Figure 2.2B shows the Catofin process diagram. Typical propylene yield is around 85% (wt). Catofin has a lower electricity requirement than Oleflex, but higher fuel requirements (Maddah 2018). Hence, the combined GHG intensity of each of them would depend on the carbon contents of the primary energy sources.
Figure 2.2B: Process Diagram of Catofin Technology
Source: CERI
The STAR (steam active reforming) technology is also based on the PDH principle but uses oxy- dehydrogenation to convert the hydrogen co-products from the reformer reactor into water, thereby releasing more heat for the reaction and altering the reaction equilibrium to effect higher propylene yields. STAR consists of five main operations including reaction, product recovery, CO2
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capture, gas separation, and fractionation to separate ethane, propane and the propylene product.
Metathesis involves a disproportionation reaction where ethylene and butenes from various sources are converted to propylene. For olefin crackers producing insufficient propylene co- product to meet supply contracts or to justify the addition of propylene polymerization units, this process can be used to convert some of the ethylene main product in order to augment propylene production. This process has already been integrated into some existing commercial olefin crackers (ICIS 1997; BASF 2019). An example of the metathesis process application is in Olefins Conversion Technology (OCT) by CB&I Lummus. It involves a fixed-bed catalytic reaction occurring around 300oC, with two primary operations involving feed purification and reaction, and product recovery.
Methanol-to-Propylene (MTP) process generates propylene under the presence of a zeolite catalyst. It involves two reaction steps where the methanol is converted to dimethyl ether (DME) and water. The methanol-water-DME system is then sent into an MTP reactor along with superheated steam at around 480oC and 1.3 bar, to produce a propylene-rich product mixture (Air Liquide 2017). Various MTP technologies have been licensed by Lurgi GmbH, Mitsubishi Chemical Corp. and JGC Corp. (Intratec 2019). Since methanol is the feed for MTP technologies, its availability is essential and is typically from natural gas (methane) to derivatives processes. A further discussion of the MTP process route is provided in (CERI 2018a).
Polyethylene Polyethylene (PE) is the largest volume commodity polymer, globally, produced from the polymerization of ethylene. There are three main types: low-density polyethylene (LDPE), linear low-density polyethylene (LLDPE), and high-density polyethylene (HDPE) that are differentiated by their molecular structures and the degree of branching. This degree of branching also determines the mechanical properties of the polymers. The three main processes for PE (whether HDPE, LDPE, or LLDPE) production are categorized in terms of the reaction system as slurry, solution, or gas-phase technologies.
LDPE is produced at higher pressures relative to HDPE, which can be produced at standard atmospheric pressure. LDPE has a lot of long-chain branching which influences the rheological properties, giving it more fluidity. The two primary routes to LDPE production are tubular and autoclave technologies (Intratec 2019). There are various designs of these technologies by different vendors (LyondellBasell 2018).
LLDPE production accounts for about 30% of global PE outputs. LLDPE production requires the addition of alpha-olefins (butene, hexene, and octene) in the presence of a catalyst. Nova Chemicals uses a solution-phase technology called SclairTech to produce LLDPE. HDPE could also be produced with this technology by changing the additive copolymer (or alpha-olefin co- monomer). Figure 2.3 shows the flow diagram of a solution technology like SclairTech. Various
June 2019 Supply Costs and Emission Profiles of Petrochemical 11 Products in Selected Hubs
PE specs are also produced using gas-phase technologies such as Innovene G by Ineos Technologies and Unipol licensed by Univation Technologies (Intratec 2019).
HDPE is mainly produced through slurry technologies. HDPE has fewer branching in its molecular structure which gives it stronger mechanical strength. HDPE also has a higher molecular weight compared to LDPE. Although gas-phase and solution technologies could be used, slurry polymerization is known to be the most effective in terms of conversion rates. Most of the existing HDPE technologies are improvements of the Ziegler process which was first used to produce HPDE and subsequently commercialized by Phillips Petroleum Company (now Chevron Phillips Chemical Company). Alpha-olefins are also used as co-monomers in some grades of HDPE.
Figure 2.3: Process Diagram of a Solution-phase PE Technology
Source: CERI
Polypropylene Polypropylene is produced using gas-phase, bulk-phase, or a hybrid of both technologies. Gas- phase reactions may occur in a fluidized-bed or stirred-bed reactor (Intratec 2019). In the bulk- phase reactor, polymerization is done using liquid propylene in tubular loop channels. This reduces the chances of polymer deposition on reactor walls. Figure 2.4 shows the diagram of a bulk-phase technology with three main operations: purification and reaction, degassing and pelletizing, and final monomer recovery (Intratec 2019). Spheripol technology by LyondellBasell is regarded as the leading bulk-phase technology (JPPC 2016; LyondellBasell 2018).
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Figure 2.4: Process Diagram of a Typical Bulk-phase Reactor Technology
Source: CERI
The Unipol polypropylene process is a leading gas-phase fluidized-bed polymerization reactor design originally licensed by DOW Chemicals until 2013 when the technology and licensing was bought by WR Grace. Figure 2.5 shows the process diagram of gas-phase technology similar to the WR Grace Unipol process, which comprises of three primary operations: purification and reaction, degassing and pelletizing, and vent recovery.
Figure 2.5: Process Diagram of a Typical Gas-phase Technology
Source: CERI
The Novolen process is another PP technology that has a stirred-bed reactor design developed by Lummus Novolen which uses a Ziegler-Natta catalyst. Process temperature is about 80-120oC and comprises of three main operations, including purification and reaction, degassing and pelletizing, and vent recovery (Intratec 2019).
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Other Olefins Technologies and Vendors • BASF-Total Cracker (metathesis): A metathesis unit is used to boost propylene production. There is an existing unit built in Port Arthur, Texas. • Superflex Process marketed by Kellogg Brown & Root: Converts hydrocarbons in the C4 to C8 range into propylene. • Deep Catalytic Cracking (DCC) licensed by Stone & Webster: Produces ethylene and propylene from gas oil and de-asphalted oils. • Mobil Olefin Interconversion (MOI) by ExxonMobil: Converts butanes/butenes, light pygas and light naphtha under zeolite catalyst into propylene and ethylene in a fluidized- bed reactor. • Lurgi Process: Converts C4 and C5 alkenes (olefins) into propylene and ethylene. • Olefin Cracking Process (OCP) by Total: Converts heavier olefins from methanol-to-olefins (MTO) into lighter olefins – mainly propylene. • Methanol-to-Propylene (MTP) process by Lurgi: Methanol from various sources (such as coal, natural gas, refinery hydrocarbons, and biomass) is converted into propylene. There are many commercial units in China and South Africa (Morse 2017; Air Liquide 2017). • Spheripol Process: Licensed by LyondellBasell is a polypropylene production technology having a high yield of the product and high selectivity catalyst for the process. This technology accounts for about 45% of deployed polypropylene technologies (LyondellBasell 2018).
Petrochemical Feedstock Sources As earlier indicated, ethane, propane, liquefied petroleum gas (LPG), and naphtha are the main feedstocks used to produce ethylene and propylene which are two major chemical building blocks in the petrochemical manufacturing process. Ethane and propane NGLs are extracted either from the gas stream in natural gas processing plants, off-gas plants, crude bitumen upgraders or as side-products from refineries (CERI 2016, 2018b). Ethane is mainly used to produce ethylene while propane is used partly for heating purposes and as a petrochemical feedstock mix (with ethane) to co-produce mainly ethylene and propylene.
Naphtha is an intermediate hydrocarbon liquid by-product containing paraffin, naphthenes, and aromatic hydrocarbons. Light naphtha (also called light straight-run [LSR] naphtha) consists of molecules such as pentanes plus that have primarily five carbon atoms (or slightly more) per molecule. It is derived from the crude oil distillation process in refineries9 or from NGLs separation in an NGL fractionation plant (McKinsey n.d.). Steam cracking of light naphtha10 (Figure 2.6) results in the production of ethylene, propylene, and a C4 stream that includes butadiene, isobutylene, and n-butenes (Petrochemicals Europe n.d.). Light naphtha from NGLs fractionation is often called natural gasoline or pentanes plus (McKinsey n.d.).
9 The refining process also yields other products such as Liquid Petroleum Gases (LPGs) and gas oils that equally serve as petrochemical feedstock for steam crackers (CERI 2016). 10 Includes heavy paraffinic naphtha that is less suited for catalytic reforming.
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Figure 2.6: Schematic Value Chain from Feedstock to Petrochemical Building Blocks
Source: CERI
Heavy naphtha contains mainly hydrocarbons with more than six carbon atoms (primarily between 7 to 9 carbon atoms per molecule) and is usually catalytically reformed into benzene, toluene, and xylenes which are also building blocks in the petrochemicals value chain (Figure 2.6). Most heavy naphtha generated in a refinery comes from the atmospheric distillation unit (McKinsey n.d.). Olefinic hydrocarbon containing naphtha derived from FCC, visbreakers and coking processes in refineries are called cracked naphthas. Naphtha composition (paraffinic, naphthenic, and aromatics content) varies, depending on the feedstock origin (Bishara, Stanislaus, and S. Hussain 1984).
Feedstocks Supply and Demand Of the three national jurisdictions considered in this study (Canada, US, and South Korea), Canada and the US are two of the top 10 NGL-producing countries, with 847 thousand barrels per day (kbpd) and 3.7 million barrels per day (Mbpd) of production, respectively (Figure 2.7). NGL comprises of mainly ethane, propane, and butane. Other than methane, NGL is an essential gas- derived feedstock for the petrochemical industry.
Based on 2017 data, the Province of Alberta hosts about 144,000 thousand cubic meters of NGLs reserves, being about 60% of Canada’s NGLs reserves (CAPP 2018). More than 80% of the western Canadian NGLs production comes from gas processing plants, with the NGLs production from western Canadian gas processing plants expected to exceed 900 Mbpd by 2028 (CERI 2018b). About 90% of the raw gas processed in western Canada is in Alberta which is Canada’s largest petrochemical hub (CERI 2018a, 2018b).
June 2019 Supply Costs and Emission Profiles of Petrochemical 15 Products in Selected Hubs
Figure 2.7: Top 10 NGLs Producing Countries, 2017
Source: (CERI 2018a) (Modified)
In the United States, around 80% of the 2018 total domestic NGLs production was from natural gas processing plants (EIA 2019). Most of the gas processing plants are located along the US Gulf Coast (USGC), in the West Texas/Oklahoma area, and in the Rockies (CERI 2014) with the USGC being the largest petrochemical cluster in the US, as well as North America (CERI 2018a).
South Korea lacks domestic energy reserves and relies on naphtha production from crude oil imports to meet the feedstock requirements for its petrochemical sector (CERI 2015; EIA 2018). South Korea will be further discussed in the feedstock demand section.
Figure 2.8: US Fourth Quarter 2018 Domestic NGLs Production
Data source: (EIA 2019). Figure by CERI
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Ethane and Propane Ethane production11 from western Canadian gas processing plants was 246 Kbpd in 2017, with Alberta contributing over 90% (Figure 2.9). All the ethane produced in Alberta is consumed within the Alberta petrochemical sector (AER 2019). CERI (2018b) concluded that the long-term demand for ethane from western Canada will be a function of the degree of expansion and modification of existing petrochemical facilities. Ethane supply to eastern Canada averages 70 Kbpd, mainly from the US Marcellus and Utica shale plays (CERI 2014). However, the US currently supplies ethane to Alberta crackers from North Dakota (Morse 2017).
Propane production from western Canadian gas processing plants was 210 Kbpd in 2017, with Alberta contributing 88% (Figure 2.9). Western Canadian ethane and propane production are expected to remain above 200 Kbpd between 2018 and 2028 (Figure 2.10). The ongoing Inter Pipeline and Pembina PDH plant projects will be soaking up 22.3 Kbpd and 23.4 Kbpd of this volume, respectively. Additionally, the new AltaGas terminal in British Columbia is on schedule to start exporting 1.2 million tonnes per year (40.8 Kbpd) of propane to Asia this year. Currently, about 85% of total Canadian propane production is exported (CKPC 2019). No remaining established reserves of ethane and propane are currently reported from eastern Canada (CAPP 2018).
Ethane and propane account for more than 70% of all domestic US NGLs production (EIA, 2019). In 2018, the US produced an annualized quarterly average of 1.7 Mbpd of ethane and 1.4 Mbpd of propane from natural gas processing plants (Figure 2.11). Unlike the Canadian case, ethane production in the US exceeds consumption (Figure 2.12).
Figure 2.9: Western Canadian Ethane and Propane Production from Gas Plants
Source: (CERI 2018a)
11 CERI (2018b) provides a discussion of the volume of ethane that is left in the natural gas stream which is not shown in Figure 2.9.
June 2019 Supply Costs and Emission Profiles of Petrochemical 17 Products in Selected Hubs
Figure 2.10: Western Canadian NGLs Production Forecast by Commodity
Source: (CERI 2018a)
Figure 2.11: US NGLs Production from Gas Plants, 2018
2 1.8 1.6 1.4 1.2 1 0.8
Production (Mbpd) Production 0.6 0.4 0.2 0 Q1 Q2 Q3 Q4
Ethane Propane Butanes Natural Gasoline (Pentanes Plus)
Source: (EIA 2019)A. Figure by CERI
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Figure 2.12: US Ethane Production and Consumption
Source: (CERI 2018a)
Naphtha In 2016, naphtha accounted for 42.5% of the global feedstock supply for ethylene production, however, this market-leading position is expected to decline below 40% by 2021 (IHS Markit 2017b) as ethylene production (especially in the North American petrochemical sector) becomes increasingly focused on cost-advantaged NGL feedstocks such as ethane (Figure 2.13). The global estimated net increase in naphtha demand by 2035 is 1.8 Mbpd (CERI 2015).
Naphtha only makes up about 4% of the refined products from Canadian refineries (CERI 2014) and is not a major feedstock for the western Canadian petrochemical sector which relies primarily on ethane feedstock. The eastern Canadian (Ontario) petrochemical sector, however, utilizes C2 to C5 feedstocks to produce ethylene, propylene and other co-products (e.g., butylene and butadiene).
In the US, naphtha and ethane dominate the petrochemical feedstocks, however, due to the lower-cost ethane production from shale and tight gas activities, several expansion projects have been planned to switch from naphtha to ethane feedstock for steam crackers (IHS Markit 2017; also see Table 2.2).
Naphtha is the predominant feedstock used in the South Korean petrochemical sector for the manufacture of ethylene, propylene and other derivatives (Nam 2017; CERI 2015, see also Table 2.3).
June 2019 Supply Costs and Emission Profiles of Petrochemical 19 Products in Selected Hubs
Figure 2.13: Global Petrochemical Feedstock Supply Growth
Source: (IHS Markit 2017a)
Table 2.2: US Steam Cracker Investments and Capacities by Feedstock Type (tonnes)
Construction Hydrogen/ Year Operator Location Feedstock FS Quantity Ethylene Propylene Crude C4 Pygas Type Fuel
2014 BASF Porth Arthur, LA Expansion Naphtha 324700 100000 52601 25976 35717 55199
2014 Westlake Calvert City, KY Conversion Ethane 251355 195000 7038 7038 195000 195000
2015 Westlake Lake Charles, LA Expansions Ethane 145657 113000 4078 4078 2476 22023
2016 Formosa Point Comfort, TX New Ethane 1031200 800000 28874 28874 17530 155917
2016 ExxonMobil Baytown, TX New Ethane 1933500 1500000 54138 54138 32870 292345
2017 Aither West Virginia New Ethane 350812 272158 9823 9823 5964 53043
2017 Shell Monaca, PA New Ethane 1933500 1500000 54138 54138 32870 292345
2017 Dow Freeport, TX New Ethane 1611250 1250000 45115 45115 27391 243621
2017 Chevron Cedar Bayou, TX New Ethane 1933500 1500000 54138 54138 32870 292345
2017 Sasol Lake Charles, LA New Ethane 1546800 1200000 43310 43310 26296 233876
Proposed 11062274 8430158 353253 326628 408984 1835714 Capacity
Source: (Fattouh and Brown 2014)
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Table 2.3: Petrochemical Production Facilities at Three Main South Korean Centres
Ulsan Yeochun Daesan Year Built 1970s 1979 1980-90 Annual 3-unit naphtha 5-unit naphtha crackers 3-unit naphtha Production crackers with 1,130 with 2,890 thousand crackers with 1,680 Capacity thousand tonnes of tonnes of ethylene thousand tonnes of ethylene annual annual production ethylene annual production capacity capacity production capacity
Source: (Park and Patel 2018)
Products Supply and Demand According to the (IEA 2018), the combined global ethylene and propylene production is about 255 million tonnes per annum (Mtpa). As earlier mentioned, ethylene and propylene form two of the basic chemicals12 that constitute the main building blocks for most of the chemical industry. According to the (IEA 2018), the combined global ethylene and propylene production is about 255 million tonnes per annum (Mtpa).
Ethylene Ethylene is the most globally produced petrochemical building block. The world consumed over 150 million tonnes (Mt) of ethylene in 2017 (WoodMackenzie 2018b) and will need almost 200 Mt by 2025 to meet global demand (Figure 2.14).
12 The other chemical building blocks include ammonia, methanol, benzene, toluene, and mixed xylenes.
June 2019 Supply Costs and Emission Profiles of Petrochemical 21 Products in Selected Hubs
Figure 2.14: World Consumption of Ethylene by Country/Region, 2018
Source: (CERI 2018a)
According to (IHS Markit 2018), demand growth is expected in the range of 6.5 million tonnes (Mt) per year between 2020 and 2025 (Figure 2.15). They suggest that to meet this demand (primarily driven by Asia – Figure 2.16), 7.0 million tonnes per year of capacity additions are needed (assuming sustainable operating rates of ~90%). IHS Markit argues that this capacity growth requires new ethylene production assets, given the inability of the base load system during 2016/17 to keep pace with demand.
Alberta’s four petrochemical plants have a total ethylene-producing capacity of 4.1 Mtpa. One of these plants is in Fort Saskatchewan. The other three are in Joffre and combine to form the world’s second-largest ethylene complex. Together, these four Alberta plants account for almost 80% of Canada’s total installed ethylene-producing capacity, with the remaining 20% located near Sarnia, Ontario (NEB 2018).
Between 2016 and 2019, a combined 11 Mtpa of ethylene capacity from new and existing facility expansion is expected in Canada and the United States, mainly riding on the back of access to cheap ethane feedstock from shale and tight gas plays (Hays 2018).
As of 2010, South Korea, with an ethylene capacity of 7.6 Mtpa, ranked among the top 5 countries in the world, making it a key contributor to northeast Asia (NE Asia) ethylene supply (Figure 2.17). As of 2015, South Korea’s ethylene capacity had reached 8.64 Mtpa, being 5.4% of the global share (Nam 2017).
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Figure 2.15: Global Ethylene Annual Demand Growth (Mt)
Source: (IHS Markit 2018)
Figure 2.16: Historical and Forecast Global Ethylene Consumption Growth, 2017 (% Share)
Source: (CERI 2018a)
June 2019 Supply Costs and Emission Profiles of Petrochemical 23 Products in Selected Hubs
Figure 2.17: World Ethylene Production by Region
Source: (IHS Markit 2016)
Propylene The world consumed over 100 Mt of propylene in 2017 but will need 135 Mt by 2025 to meet anticipated global demand growth (WoodMackenzie 2018a). The world total propylene capacity is expected to exceed 100 Mt by 2024 (Figures 2.18). In North America, 20 Mt of propylene was produced in 2013. However, propylene capacity is expected to increase to 38 Mt in 2023 to account for 30% of the global market (Economic Plant 2017). In Canada, propylene accounts for about 6.4% of the petrochemical production13 (Figure 2.19).
13 Ethylene is the primary petrochemical product made in Canada (regardless of the feedstock) and accounts for 51.6% of the relative petrochemical production (tonnes basis) (Statistics Canada 2011).
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Figure 2.18: Global Base Chemical Total Capacity Forecast by Market
Source: (CERI 2018a) (Modified)
The ongoing Inter Pipeline and CKPC projects in Alberta will bring an additional 525 and 550 Ktpy of propylene, respectively, to the total Canadian production (CKPC 2019; Chemicals Technology 2016). However, Inter Pipeline will only polymerize about 15% of their production and sell the rest to North American Polypropylene (NAPP) under a 25-year service agreement (Chemicals Technology 2016). CKPC, on the other hand, plans to convert all their propylene product into polypropylene (CKPC 2019).
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Figure 2.19: North American Chemical Capacity Forecast
Source: (CERI 2018a) (Modified)
Polyethylene (PE) The global PE capacity is expected to increase from 108.3 Mt in 2016 to 150 Mt by 2027, with production also growing from 93 Mt to 133.6 Mt by 2027 (Mistry 2017). Between 2017 and 2027, the cumulative annual growth rate (CAGR) for PE demand is expected to range from 0.7% in western Europe (the lowest regional growth) to 5.3% in Asia (the highest regional growth) (S&P Global Platts 2019, also see Figure 2.21). From the S&P analysis, over the same period, the North American PE demand CAGR is forecasted to be 1.9%, with the price for 65% of the US PE production driven by oil prices (RTi 2018).
From 2016 to 2019, approximately 6.8 Mtpa of additional PE capacity is expected to be added in Canada and the US, with an additional 3.28 Mtpa after 2020 (Hays 2018). With a PE capacity that reached 23 Mt in 2017, the US in the same year exported 3.47 Mt of PE (Hays 2018). Several upcoming PE plants are planned for the USGC (Figure 2.20).
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Figure 2.20: New and Upcoming USGC Ethylene and PE Plants
Source: (ICIS 2018)
Polypropylene (PP) The global PP capacity is expected to increase from 76.6 Mt in 2016 to 89 Mt by 2023, with a gradual speculative capacity of about 9.8 Mt required by 2027 for market balance at an 88% rate (Mistry 2017). Although the global demand for PP is expected to annually average around 3% between 2017 and 2027 (Mistry 2017), for the same period, the cumulative annual growth rate for PP demand will vary in different global regions, from 0.6% in western Europe (the lowest regional growth) to 4% in Asia (the highest regional growth) (S&P Global Platts 2019, also see Figure 2.21). Most of the growth in Asia comes from northeast Asia (particularly China) where demand-driven, on-purpose capacity has grown the fastest at around 24% over the last seven years (Morse 2017).
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Figure 2.21: Polyethylene and Polypropylene Global Trade Flows by Region, 2017
Canada Russia
USA China
India
Australia
Source: (S&P Global Platts 2019). Modified by CERI.
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June 2019 Supply Costs and Emission Profiles of Petrochemical 29 Products in Selected Hubs Chapter 3: GHG Emissions, Mitigation and Regulations
GHG Emissions from the Petrochemical Industry The petrochemical industry (including the processes required to produce ethylene and propylene), requires a substantial amount of energy use and emits considerable amounts of greenhouse gases. Emissions are produced during carbon dioxide separation from the feedstock, de-coking the furnace and reaction system, fuel combustion, and methane leaks throughout the production stages and flare operations.
There are three primary sources of GHG emissions from petrochemical plants, including:
• Heating demand emissions, • Electricity demand emissions, and • Process chemistry emissions.
While heating and electricity are easily recognized from the primary energy consumption to produce heat and power for the process, process chemistry emissions occur when GHGs generated from reactions and processing operations in the plant are released as part of the process or unintentionally released to the environment. The main GHGs from petrochemical facilities are carbon dioxide, methane, and nitrous oxide. Heating and process chemistry emissions are often seen as direct emissions, whereas emissions due to electricity usage are usually considered as indirect emissions. Some petrochemical plants are equipped with cogeneration facilities for the in-house generation of heat and power.
Carbon dioxide is the predominant GHG emitted routinely from the petrochemical sector. However, GHG emissions intensity usually vary, depending on the type of petrochemical process and technology in use, in addition to feedstock type. The majority of emissions arise from the overall energy use of the processes, unlike process chemistry emissions which are created from the chemical conversions and separations of feedstocks or products. Depending on the type of process, technology, feedstock and primary energy source, energy use emissions may account for between 75% to over 90% of total emissions (Tao Ren, Patel, and Blok 2006).
For olefin cracking, the furnace is usually the highest source of GHG emissions due to fuel combustion at a petrochemical facility. Apart from cracking furnaces, other sources include boilers, vapour destruction units, cogeneration units, flares and incinerators, emergency generators, and process area fugitives (US EPA 2012; Trinity Consultants 2012; Dow Chemical Company 2014; Environmental Resources Management 2014; RTP Environmental Associates 2014).
In many plants, a portion of the feedstock is used as fuel for the process. In such cases, heating emissions can be estimated based on embodied carbon in the feedstock. Table 3.1 shows the
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intrinsic CO2 emission factors for the feedstocks considered in this study. It can be observed that ethane has the lowest intrinsic CO2 emission factor.
Table 3.1: Intrinsic CO2 Emission Factors for Various Feedstocks
Feedstock Type CO2 Emission Factor (Kg CO2/MBTU) Hydrogen 0.00 Methane 52.28 Ethane 59.58 Propane 63.07 LPG1 64.20 Naphtha 66.51 Source: (Benchaita 2013), CERI
Mitigation Pathways (Processes and Technologies) Mitigation strategies for petrochemical emissions are often described – depending on the country – in terms of the attributes of the processing technologies as Best Practice Technology (BPT), Best Available Technologies (BAT), or Best Available Control Technology (BACT). Although BPT and BAT are often used interchangeably, BATs still need to be de-risked due to their limited or zero commercial level deployment whereas BPTs are already in common use (Benchaita 2013). BACT is mainly used in the US for benchmarking of new projects for Environment Protection Agency (EPA) approval.
Over the last decade, various studies have attempted to identify opportunities to improve efficiency and reduce emissions from the petrochemical sector by comparing the performances of existing facilities to BPTs. An EPA study (IEA 2009) investigated 57 processes to highlight the total estimated energy saving potentials by applying BPTs that meet heating electricity and processing requirements. The study reported various energy saving potential for petrochemical industries in various countries, as shown in Table 3.2.
1 Based on propane (30%) and butane (70%) compositions
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Table 3.2: Energy Reduction Potential by Country
Final Process Energy and Feedstock Use Final Process Energy and Feedstock Use (Including Electricity) (Excluding Electricity) Definition Reported BPT Reported BPT Energy Energy Improvement Energy Energy Improvement Country EEI2 EEI Use Use Potentials Use Use Potentials (PJ/yr) (PJ/yr) (PJ/yr) (PJ/yr) USA 7321 5655 0.77 22.70% 6412 4928 0.77 23.10% China 5323 5332 1 (-0.2) % 4301 4514 1.05 (-5 )% Japan 2252 1959 0.87 13% 2053 1800 0.88 12.30% Korea 1562 1594 1.02 (-2.1%) 1416 1477 1.04 (-4.3%) Saudi Arabia 1369 1058 0.77 22.70% 1369 1058 0.77 22.70% Germany 1241 1209 0.97 2.60% 1064 1068 1 (-0.3%) India 1096 1133 1.03 (-3.3%) 1096 1133 1.03 (-3.3%) Benelux Union 1092 1147 1.05 (-5.1%) 1004 1077 1.07 (-7.3%) Taiwan 859 738 0.85 14.10% 736 640 0.87 13.10% Canada 843 766 0.91 9.20% 776 712 0.92 8.20% France 714 631 0.88 11.50% 627 561 0.9 10.50% Brazil 651 576 0.88 11.60% 572 513 0.9 10.40% Italy 457 408 0.89 10.60% 389 354 0.91 9.10% World 35217 29940 0.85 15.00% 31529 26990 0.86 14.40%
Source: (IEA 2009)
There are five main mitigation pathways via BPT or BACT. These include:
• Energy efficiency (e.g., CHP, better combustion practice, recycling, etc.) • Fuel switching (e.g., bioenergy, low carbon fuels, etc.) • Leak detection and repair (LDAR) • Decarbonization of electricity (e.g., use of renewable electricity, clean electricity, etc.) • Carbon capture, and storage (e.g., from the cracking process, from the power source, etc.)
The International Energy Agency (IEA 2018) identified five emission mitigation levers for the petrochemical industry as alternative feedstocks, energy efficiency, plastic recycling, coal to natural gas, and carbon dioxide capture, utilization and storage (CCUS). Figure 3.1 shows the expected contributions from the mitigation levers to achieve CO2 emission reduction of 45% by 2050, even as the industry grows by 40% over this period (IEA 2018). Plastics recycling is expected to usher a reduction of 9% through improvements in collection rate, yield rate and displacement of virgin hydrocarbon demands in the petrochemicals supply chain. The largest reductions are expected from CCUS (35%), coal to natural gas feedstock transition (25%, mainly from Asia), and
2 EEI is Energy Efficiency Index
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energy efficiency improvements (25%). CCUS is expected to deliver the most reduction of all the mitigation levers.
Figure 3.1: Expected Contributions of IEA Mitigation Levers to CO2 Emission Reduction by 2050
Source: (IEA 2018)
Greenfield Facilities Greenfield facilities have the advantage to implement cost-effective BPTs as they are relevant for new facility builds. Maximum savings in energy consumption and emissions are achieved by deploying BPT in new projects. However, this could present a major cost hurdle in terms of initial capital investment needed (Bazzanella and Ausfelder 2017). This calls for simultaneous considerations of economic, efficiency and environmental performances of the mitigation options to be adopted.
Brownfield Facilities Brownfield facilities have limited mitigation options, especially for older facilities. Any improvement would be incremental. Improvement opportunities for existing facilities are dependent on anticipated technological advances in areas such as catalyst systems design, reactor optimization through advanced process modelling, control and digitalization, and heat integration (Bazzanella and Ausfelder 2017). Based on industry reports, incremental improvements in integrated facilities can improve yields by between 2% to 5%, decrease energy intensity by between 0.2% to 1% per year, and improve product quality by up to 50% (Bazzanella and Ausfelder 2017).
Carbon capture and storage (CCS): CCS is considered as a mitigation pathway that could remove 50% to 90% of the CO2 emissions from a source (Adams et al. 2017). The CO2 must be captured, compressed and stored permanently. Depending on the energy source for the capture plant, net emissions could increase by about 20% to 30% for a natural gas combined cycle (NGCC) powered capture (Equistar Chemicals LP, 2012, Griffin et al. 2017) and up to 38% for coal combustion power plants (Adams et al. 2017). There are now commercial facilities capturing CO2 for
June 2019 Supply Costs and Emission Profiles of Petrochemical 33 Products in Selected Hubs enhanced oil recovery (EOR) and permanent storage in saline aquifers. The Boundary Dam CCS plant removes CO2 from a power plant for EOR applications in Saskatchewan. The Alberta Quest CCS project – also in Canada – was commissioned in 2015 and has since captured and stored about 4 Mt of CO2 as at May 2019. Experiences gained from building and operating these facilities are helping to de-risk CCS technologies and new projects globally. The major risk factors include the total cost of implementation, the possibility of stored CO2 leakage, and uncertainties about the maintenance and monitoring of a CCS site, post-injection. These projects will need more time for operation and management to consolidate current understanding of their performance and durability.
Nonetheless, deployment of CCS mitigation in the petrochemical sector has yet to fully catch on. Even though it is common for permit applications for new petrochemical facilities to cite CCS for emission mitigation in their BACT analysis, none has ever gone ahead to deploy CCS in their final designs. Moreover, project feasibility studies have suggested that the cost of capture and compression, alone, would increase the total capital cost by more than 25% (US EPA 2012; Adams et al. 2017). Currently, apart from the utilization of captured CO2 for enhanced oil recovery or as feedstock for chemical industries, there is no incentive to recover capex. Therefore, it will only be done on regulatory compliance grounds.
Energy Efficient Design and Operation: Energy efficiency can be a major option to reduce emissions, even with increased production. For instance, the European chemical industry total production increased by 78% between 1990-2014. However, fuel and power consumption fell by 22% (Bazzanella and Ausfelder 2017). Energy use by the furnace accounts for about 60% of total requirements of an olefin manufacturing plant, whereas thermal efficiencies of most furnaces are between 75-90%, although more often in the lower range. Due to design and operational constraints, theoretical maximum efficiency is said to be about 92% high heating value (HHV) (Trinity Consultants 2012).
Integrated energy efficient designs can optimize steam, fuel, and overall energy use of a steam cracker. By integrating energy use, waste heat can be minimized in the plant. Designing for and maintaining efficient heat transfer attributes in the furnace and boilers also minimize fuel consumption, saving money and cutting emissions (US EPA 2012). These can be realized by leveraging the opportunities to improve energy efficiency by reducing heat losses from 1) flue gas, 2) process effluent, and 3) firebox walls. Other opportunities include (RTP Environmental Associates 2014; Morse 2019):
• Maintaining the correct proportions of nitrogen in the combustion air and fuel mixture; nitrogen absorbs heat from the combustion, reducing the efficiency • Providing the temperature required to initiate and complete combustion • Generating adequate turbulence or interaction between combustion fluids to achieve proper mixing • Ensuring appropriate residence time for the combustion reaction to complete and for heat transfer
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• Periodic tune-ups and maintenance, continuous monitoring, routine process cleaning and maintenance, and reduced decoking cycles • Maintaining optimal operating rates (e.g., calibration of oxygen analyzers, temperature measurements, flow measurements, and replacement of furnace radiant section tubes) • Avoiding the use of intermediate tankage to provide feed from one unit to another • Processing lower intermediate product quality specifications, without affecting or degrading operations and final product quality • Deploying different catalysts that are more active or more selective, or having longer lifetimes • Implementing structured packaging in columns to improve separation and reduce energy use through less recycling, pumping, and heating • Applying the concept of transfer of efficiencies for rotating equipment with significant electricity requirements by utilizing higher efficiency power sources (such as hydro) • Informing decision making through digitalization and process analytics via artificial intelligence, advanced process control and optimization.
Fuel switching: the use of renewable or low carbon fuels for the process has been reported to reduce facility emissions by between 20% to 40% (US EPA 2012; IEA 2018). When combined with energy efficiency, it can provide significant GHG reduction for a petrochemical facility. Commonly switched fuels would be natural gas or hydrogen for coal or diesel. Steam crackers yield up to 4.3% hydrogen which can be co-burned with the main fuel in the furnace to reduce emissions (Benchaita 2013). Some operators have reported burning fuel blends of 25% to 85% hydrogen contents in their plants (US EPA 2012) RTP Environmental Associates, 20143).
However, at higher hydrogen contents, combustion temperature also increases, triggering the generation of more NOx emissions. Up to 60% higher NOx emissions than from firing low hydrogen content fuels can occur. Consequently, additional investments in ultra-low NOx emission burners and selective catalytic reduction might be needed (RTP Environmental Associates 2014). Some studies (Griffin, Hammond, and Norman 2018; Bazzanella and Ausfelder 2017) have highlighted fuel switching to renewables such as biomass. This will reduce/remove emissions but can drive other environmental concerns such as soil erosion, water shortage, use of pesticides and eutrophication from fertilizers. There are also issues related to logistics and transport of fuel feedstock from long distances that might cancel the avoided emissions.
Decarbonization of electricity and electrification: emissions due to electricity use in the plant is an indirect source and depends on the intensity of the generator. Where grid electricity is used, the average grid emission intensity can give a good idea about the impact of electricity requirements. The use of renewable and clean electricity can cut electricity use-related emissions.
Electrification of processes offers the opportunity to adopt electricity-based processes instead of burning fuels directly. This has been of interest to some companies for steam generation. This
3 Shell Chemical Appalachia’s ethane cracker plant, which is currently under construction in Pennsylvania, US.
June 2019 Supply Costs and Emission Profiles of Petrochemical 35 Products in Selected Hubs would require the replacement of natural gas-fired boilers with electric boilers or hybrid boilers (Bazzanella and Ausfelder 2017). This can reduce fuel consumption by up to 60% (Bazzanella and Ausfelder 2017; DOE 2015). Hybrid boilers can switch between natural gas and electricity; with fast response time and lower direct emissions. They can take advantage of cheaper off-peak electricity and can absorb surplus supplies of intermittent renewable power generation, as a component of demand-side management (Bazzanella and Ausfelder 2017; DOE 2015). The main challenge is that electricity cost might become very high for processes requiring high temperatures.
Leak Detection and Repair (LDAR): Leak detection and repair can be used to combat fugitive emissions from the facilities due to releases of process fuels (such as natural gas – methane, fuel gas, and cracked gas), process chemistry emissions, or GHGs entrained in the feedstock which leaks from any part of a petrochemical plant. LDAR programs can be achieved through:
• Leakless/sealless technologies • Direct sensing and measurement • Remote sensing and measurement • Auditory, visual, olfactory monitoring and assessment
There is much left to be understood on LDAR effectiveness and the best approaches for deploying the technologies and operator training requirements needed to reduce emissions. Facility coverage area and potential emission sources need to be inventoried in order to improve effectiveness.
GHG Emissions and Carbon Regulations Canada Key legislation and regulations The Canadian Environmental Protection Act (CEPA) (1999) is an important part of Canada’s federal environmental legislation (including climate change action and carbon management legislation).
• Greenhouse Gas Reporting Program (GHGRP) under Section 46 of the CEPA: Operators of facilities that meet the criteria identified in the annual Notice with respect to reporting of greenhouse gases, published in the Canada Gazette, are required to report their GHG emissions to Environment and Climate Change Canada (ECCC) on an annual basis. All facilities that emit 10 kT of CO2e/year or more are required to submit a report to ECCC by June 1 of each year. The program is mandatory for those who meet the requirements and has collected data from facilities since 2004 (ECCC 2019).
Greenhouse Gas Pollution Pricing Act (2018) implements a federal carbon pricing system that includes two key elements: 1) a charge on fossil fuels that would be paid by fuel producers or distributors, and 2) an output-based pricing system (OBPS) for industrial facilities that are emissions-intensive and trade-exposed (Government of Canada 2018).
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• The aim of the OBPS is to minimize competitiveness risks for emissions-intensive trade- exposed (EITE) industrial facilities while retaining the carbon price signal and creating incentives to reduce GHG emissions. • The charge would not be applied to fuels used at industrial facilities that are registered under the OBPS. Instead, they would pay the carbon price on the portion of emissions that exceed an annual output-based emissions limit. • In jurisdictions where the backstop applies, the OBPS will apply to industrial facilities that emit 50 kT CO2e or more and for which an output-based standard is specified (regulated facilities), or that emits between 10 and 50 kT CO2e per year and whose application for voluntary participation is approved (opt-in facilities). • Facilities whose emissions are below their annual facility emissions limit will receive surplus credits from the federal government. Facilities whose emissions are above their limit will have three options to meet its obligation: 1) paying a charge to the federal government (set at the same level as the fuel charge), 2) submitting surplus credits, and 3) submitting eligible offset credits.
Canadian Environmental Assessment Act (2012) does not require a federal environmental impact assessment for the construction, operation, decommissioning and abandonment of petrochemical projects. However, the environmental assessment process is mandatory for industrial facilities located in a wildlife area or migratory bird sanctuary, as well as a railway yard with seven or more tracks or a total track length of 20 km or more.
Several regulations that may impact petrochemical facility development are currently being adjusted or are under review. These include:
• Multi-Sector Air Pollutants Regulation • Proposed Federal Methane and Carbon Emissions Reduction Programs • Greenhouse Gas Reporting Changes • Canadian Environmental Assessment Agency Bill C-69
Major policy documents • Pan-Canadian Approach to Pricing Carbon Pollution (2016) • Pan-Canadian Framework on Clean Growth and Climate Change (2016) • Federal Actions for a Clean Growth Economy: Delivering on the Pan-Canadian Framework on Clean Growth and Climate Change (2016) • Technical Paper on the Federal Carbon Pricing Backstop (2017) • Guidance on the Pan-Canadian Carbon Pollution Pricing Benchmark (2017) • Carbon Pricing: Regulatory Framework for the Output-Based Pricing System (2018)
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Alberta Key legislation and regulations Climate Change and Emissions Management Act (CCEMA) (2003)
• Carbon Competitiveness Incentive Regulation (AR 255/2017) under the CCEMA outlines the mechanism of the hybrid carbon pricing system in Alberta. The system is composed of an output-based allocation (OBA) system and a provincially mandated carbon levy. Both the OBA benchmark and carbon levy progressively tighten to drive emissions out of the economy. Several compliance options other than directly paying the mandated levy are provided (Province of Alberta 2018). • Specified Gas Reporting Regulation (AR 251/2004, amended in 2018) requires facilities that emit 10 kT CO2e/year or more to submit annual reports on their emissions. Facilities subject to this Regulation report their GHG emissions through the federal government’s Single Window Information Management System (Government of Alberta 2019).
Climate Leadership Implementation Act (2017)
• Climate Leadership Regulation (2016)
Environmental Protection and Enhancement Act (EPEA) (2000): Alberta Environment and Parks regulate petrochemical facilities under the EPEA through industrial approvals.
• Environmental Assessment (Mandatory and Exempted Activities) Regulation under the EPEA lists activities that are required for the environmental impact assessment process. A provincial assessment is mandatory for the construction, operation or reclamation of an ethylene or ethylene derivative manufacturing plant, as well as a benzene, ethylbenzene or styrene manufacturing plant (Government of Alberta n.d.).
Ontario Key legislation and regulations Environmental Protection Act (1990)
• Greenhouse Gas Emissions: Quantification, Reporting and Verification Regulation (O.Reg. 390/2018) under the Ontario Environmental Protection Act requires facilities (including petrochemical production) generating more than 10 kT but less than 25 kT of CO2e/year to report their total GHG emissions annually. Facilities emitting 25 kT of CO2e/year or more are required to have their emission reports independently verified (Government of Ontario 2019b). • Proposed Industrial Emission Performance Standards (2019) under the Ontario Environmental Protection Act will impose a carbon tax like emissions standard on industrial facilities. Implementing an Ontario Emission Performance Standard will provide flexibility for Ontario circumstances as an alternative to the federal OBPS portion of the federal Greenhouse Gas Pollution Pricing Act. The program is expected
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to be in place by summer 2019 and to have it apply to emissions as of January 1, 2019 (Government of Ontario 2019a).
Currently, without the Industrial Emission Performance Standards in place, the federal backstop with OBPS is applied in Ontario after the provincial government revoked the Cap and Trade Regulation (Ontario Regulation 144/16) through the Climate Change Mitigation and Low-carbon Economy Act, 2016 and the Cap and Trade Cancellation Act, 2018. Large industrial emitters are also required to report their annual GHG emissions under the federal GHGRP through the Single Window Information Management System (ECCC 2019).
Major policy documents • Technical Standards to Manage Air Pollution (2018), Chapter 7.0 Petrochemical – Industry Standard. The purpose of this technical standard is to identify and implement best available controls to minimize air emissions of benzene and 1,3-butadiene from Ontario petrochemical facilities. With respect to facilities, this industry standard applies to every facility that is part of a class identified by NAICS code 325110 (Petrochemical Manufacturing) (Government of Ontario 2018). • Ontario’s Five-Year Climate Change Action Plan 2016-2020 (Government of Ontario 2016)
The United States Key legislation and regulations The Clean Air Act (1970) is the comprehensive federal law that regulates air emissions from stationary and mobile sources and requires the EPA to set National Ambient Air Quality Standards for six common air pollutants. For major sources, Section 112 requires that the EPA establish emission standards (Maximum Achievable Control Technology standards) that require the maximum degree of reduction in emissions of hazardous air pollutants. Major sources are defined as a stationary source or group of stationary sources that emit or have the potential to emit 10 tonnes per year or more of a hazardous air pollutant or 25 tonnes per year or more of a combination of hazardous air pollutants (US EPA 2017).
Greenhouse Gas Reporting Program (GHGRP, referred to as 40 CFR Part 98) requires reporting of GHG data and other relevant information from a total of 41 categories (including petrochemical production) of large industrial emitters in the United States. Facilities are generally required to submit annual reports under Part 98 if GHG emissions from covered sources exceed 25 kT CO2e/year (US EPA 2018).
• 2015 Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule (Final Rule, 81 FR 89188, 2016) finalize amendments to specific provisions in 29 subparts of the Greenhouse Gas Reporting Rule (including Subpart X Petrochemical Production) to be phased in over the 2016, 2017, and 2018 reporting years. Under the Mandatory Reporting of Greenhouse Gases rule, owners or operators of facilities that produce petrochemicals (acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, and methanol) must report emissions from
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petrochemical processes and all other source categories located at the facility for which methods are defined in the rule (US EPA 2016). • Subpart X - Petrochemical Production Monitoring Checklist. In addition to the monitoring requirements under 40 CFR subpart C for the Tier 3 (for CH4 and N2O emissions) and Tier 4 Calculation Methodologies (for CO2) and the requirements under 40 CFR subpart Y for flares, other applicable parameters for each petrochemical production process unit must be monitored (US EPA 2009). • Subpart X - Technical Support Document for the Petrochemical Production Sector: Proposed Rule for Mandatory Reporting of Greenhouse Gases (2008). For this GHG reporting rule, the petrochemical production source category only considers the production of acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, and methanol, because production of GHGs from these processes has been recognized by the Intergovernmental Panel on Climate Change (IPCC) to be significant compared to other petrochemical processes (US EPA 2008).
National Emission Standards for Hazardous Air Pollutants for Source Categories: Generic Maximum Achievable Control Technology Standards and National Emission Standards for Ethylene Manufacturing Process Units: Heat Exchange Systems and Waste Operations (2005, 40 CFR Part 63, Subpart YY).
South Korea Key legislation and regulations The Clean Air Conservation Act (1995), Article 35
The Chemicals Control Act (in force since 2015) focuses on chemical reporting and chemical accident prevention (ChemSafetyPro 2019).
The Act on Integrated Control of Environmental Pollution-Generating Facilities (2015) integrates the governmental licensing/approval systems for certain pollution-generating facilities currently regulated by various environmental laws such as the Clean Air Conservation Act. The facilities eligible for an integrated license/approval are those that 1) emit at least 20 t/year of air pollutants, or 2) discharge at least 700 m3/day of industrial effluent (Kwon et al. 2017).
The Act on Registration and Evaluation, etc. of Chemical Substances (K-REACH) (2013, amended in 2018, in force since 2019). Under amended K-REACH, any person who intends to manufacture or import a new chemical substance or at least one t/year of an existing chemical substance shall register the chemical substance according to the specific requirements (ChemSafetyPro 2018).
The Framework Act on Low Carbon, Green Growth (2010, amended in 2013) provides the legal base for the subsequent implementation of the Korea Emissions Trading Scheme (KETS, see below) (International Carbon Action Partnership 2019).
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The Act on Allocation and Trading of Greenhouse Gas Emissions Allowances (the Emissions Trading Act) (2012), along with its Enforcement Decree (2012), introduces a system for trading GHG allowances through market mechanisms, and stipulates government actions, institutions, and timelines for the KETS (International Carbon Action Partnership 2019).
• The Master Plan for the Emissions Trading Scheme and the Phase I National Allowances Allocation Plan (2014) were announced in 2014 to implement the Emissions Trading Act.
The Korea Emissions Trading Scheme (KETS) was launched in 2015 and is currently in its second phase, which runs from 2018 to 2020. The KETS became the first nationwide mandatory emissions trading system (ETS) in East Asia and the second largest carbon market after the European Union ETS. The KETS covers 591 of South Korea’s largest emitters from 64 subsectors (including the petrochemical industry) which are responsible for approximately 68% of national GHG emissions. Under this system, the inclusion thresholds are more than 125 kT CO2e/year for a company, and more than 25 kT CO2e/year for a facility. As of 2018, the allowance price (average secondary market price) was equal to US$20.62 per t/CO2e (International Carbon Action Partnership 2019; Asian Development Bank 2018).
The Greenhouse Gas and Energy Target Management System (launched in 2012) enables the mandatory collection of verified emissions data from establishments and businesses that emit large quantities of GHGs or consume large amounts of energy but are not included in the ETS. From 2014, it has been applicable to businesses emitting 50 kT CO2e/year or more, or consuming 200 TJ of energy or more, and to establishments emitting 15 kT CO2e/year or more, or those consuming 80 TJ of energy or more (Ministry of Environment, Republic of Korea 2017).
June 2019 Supply Costs and Emission Profiles of Petrochemical 41 Products in Selected Hubs Chapter 4: Methodology
In order to quantify GHG emissions and calculate supply costs for the petrochemical products and their derivatives examined in this study, CERI considers hypothetical integrated petrochemical facilities located in each of the hubs of interest to transform single and mixed feedstocks into the desired final products.
The following feedstock and final product scenarios are assessed:
A. Ethane-only to polyethylene and co-products B. Ethane+propane feedstock mix to polyethylene and co-products C. LPG-only (propane + butane) to polyethylene and co-products D. Naphtha-only to polyethylene and co-products E. Propane-only to polypropylene and co-products
For an integrated facility, polyethylene is considered the main product of steam cracking whereas polypropylene is the main product of propane dehydrogenation. Figure 4.1 shows the petrochemicals processing pathways analyzed for the feedstock scenarios. The co-products evaluated are propylene (from steam cracking), ethylene (from PDH), hydrogen, and methane (fuel gas). The PDH process consumes only propane as feedstock to produce propylene, which then polymerizes. Overall material balance is achieved to determine total amounts of the rest of the other co-products.
Figure 4.1: Process Diagram of Integrated Processes for Polypropylene and Polyethylene Production using Various Feedstocks
As earlier indicated, CERI’s approach is to use petrochemical hub-level analysis to evaluate the effect of location (e.g., feedstock availability, supporting infrastructure, access to destination markets for products) and carbon regulations on the supply costs of PE and PP products.
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For NGL-derived feedstock blends, CERI utilized the quantities of products estimated for a generic facility from a process input-output model to determine the main product, co-product, and other side-product yields. Product supply costs were calculated using a supply cost model. Further details of the modelling are presented in the following sections.
Petrochemical Processes Input-Output Modelling The purpose of a process input-output model is to estimate product yields for the various feedstock options into the petrochemical plant. We assume that this is a hypothetical facility located in each of the hubs in the three countries (Canada, the US and South Korea) considered in this report. Process options are based on either steam cracking or PDH along with a polymerization unit. The polymerization unit is intended for the primary (main) product. We assume that co-products are recovered for sales.
For our chosen plant capacity and depending on the feedstock-process-product combinations and the technologies examined, published data on yields are used to evaluate feedstock consumption and quantities of co-products and other less valuable side products. Co-products of interest are hydrogen, methane, ethylene, propylene and aromatics, whereas the other side- products of interest are the greenhouse gases such as CO2, CO (fully oxidized to CO2) and N2O. Levi and Cullen (2018) used a similar approach to map global flows of various feedstocks into various chemical products.
Figure 4.2 shows the typical yields of petrochemical products from steam crackers according to industry reported data (LyondellBasell 2018). Apart from the emissions generated from the chemical conversion of some portions of the feedstocks into side-products, the other two sources of emissions are from fuel consumption for heating and electricity. Although some petrochemical plants may have in-house electricity generation, electricity emissions are usually considered indirect emissions from the plant operations.
GHG emissions from heating and electricity requirements can be determined from the primary energy consumption to provide these energies.
Total facility emissions can be computed for both direct and indirect emission sources. Carbon dioxide equivalent emissions of methane and nitrous oxide are calculated using IPCC(AR5) global warming potentials (GWP) of 28 and 265, respectively.
Further information and the data sources for product yields of various processes and technologies, in addition to their electricity and heating requirements, are provided in Appendices B and C. The process model uses industry estimates of propylene (and polypropylene) yields from PDH plants of 80%. Data on two commercial PDH technologies (Oleflex and Catofin) were utilized. Data on polymerization technologies are obtained from vendors and industry reports.
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Figure 4.2: Yields of Products for Various Single Feedstocks to Olefin Steam Cracker (product yield is for each feedstock)
Source: (Lyondellbasell, 2018, modified by CERI)
Costs and Economic Impact Assessment CERI utilized a supply cost model (SCM) to assess the costs related to the production of PE and PP petrochemical products from crackers that utilize single feedstock or feedstock mixes (as earlier mentioned). The supply cost assessment considered the costs associated with PE and PP shipments to the US and China destination markets to provide a landed supply cost.
Supply Cost Model: Components and Method CERI’s supply cost model (SCM) comprises the following sub-modules:
1. Project description: This module captures the information on capacity and feedstock 2. Project costs: Captures costs associated with a. Capital expenditure (CAPEX), b. Construction time (years), and c. Operating expenditure (OPEX)
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3. Inflation, return and exchange rates:1 This module accounts for CAPEX, OPEX and price inflation. The discount and exchange rate form the other components of this module. 4. Taxation: The fiscal parameters in this module include the government corporate tax (Federal and Provincial), capital depreciation rate, and carbon tax.
Two additional modules complement the SCM, namely:
Cash flow model: This module accounts for the cash flow in the build phase and during operations.
The net cash flow is discounted over a given duration (30 years in this study) with a discount rate (internal rate of return [IRR] of 10% in this study).
Transportation costs: This module is assessed separately to allow CERI to determine the plant gate (or free on board [FOB]) supply cost and landed supply costs. Transportation costs refer to the cost associated with getting the product to the destination market. The cost associated with transporting feedstock to the cracker2 is captured as part of the OPEX in the SCM.
The supply cost will be the cost in dollars per tonne ($/t) in 2018 constant dollars that sets the net present value of the NCF to zero.
General Model Assumptions The following general assumptions underpin the data input and components in CERI’s SCM (Appendix A).
Capital Requirement It is assumed that the funds required to construct the petrochemical complexes are available through 100% equity financing. Therefore, no debt servicing is involved.
Feedstock Prices CERI used 2018 regional prices of the various feedstocks included in our process model and inflated future prices by 2%. Feedstock prices in South Korea (importing country) are estimated by adding transportation costs to the prices in USGC (exporting country).
Labour All the plants modelled are assumed to have been constructed and operated in the four petroleum hubs using non-union labour. Using unionized workers would result in higher cost levels which vary as a function of the location (Petrochemical Update 2019).
1 (Bank of Canada 2019) 2 Referred to as the feedstock transport cost
June 2019 Supply Costs and Emission Profiles of Petrochemical 45 Products in Selected Hubs
Location Factors One of the challenges of running the SCM for the USGC, Alberta, Ontario, and South Korea for the petrochemical complexes represented by feedstock scenarios A to E was the unavailability of readily accessible detailed construction cost data. To compensate for the paucity of data, CERI applied location factors (Table 4.1) on a US cost basis to the cost values retrieved from reference studies, data sources or CERI estimates for petrochemical plants constructed in the USGC (Sasol 2017; Compass International 2018; Petrochemical Update 2019). The location factor takes into account the following variables in different locations (Compass International 2018):
• Disparities in construction materials and labour rates • Productivity differentials • Differences in the utilization of construction equipment and power tools • The importation of construction materials and major capital equipment/machinery • Design costs • Exchange rates • Freight costs • Taxes • Import duties
CERI classified the location factors used in the study on whether the petrochemical complex is the first of its kind (FoiK) or not the first of its kind (NFoiK) in the location. Location factors are higher for Foik projects (Table 4.2) as a steep learning curve is expected in dealing with the government policies, regulatory requirements and/or local challenges. In determining a base case location factor for FoiK projects, it is considered that the FoiK impact on the construction cost would be moderated or accentuated by the presence or absence of supporting infrastructure, access to labour, and industrial construction know-how. In this study, a greenfield petrochemical plant constructed in Ontario is assumed to be a FoiK project and hence assigned a FoiK construction cost location factor – since no new projects have been built/slated for the Sarnia hub recently.
The location factor was also used to estimate the cost information where the construction cost was unavailable in the USGC but available for plants in other petrochemical hubs.
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Table 4.1: Construction Cost Location Factors for NFoiK Petrochemical Plants, 2018 USGC Cost Basis
Location Location Factor Remarks Canada – Alberta 0.983 For Canada-based chemical, process, Industrial Heartland or manufacturing facilities (utilizing some imported materials and equipment) Canada – Ontario 0.984 For Canada-based chemical, process, (Sarnia and Corunna) or manufacturing facilities (utilizing some imported materials and equipment) South Korea 0.965 For South Korea-based chemical, process, or manufacturing facilities (with a high-content of imported engineered equipment6).
Table 4.2: Construction Cost Location Factors for FoiK Petrochemical Plants, 2018 USGC Cost Basis
Location Location Factor Remarks Canada – Alberta 1.1 CERI estimate. Considers the existence Industrial Heartland of an industrial cluster in Alberta, the presence of supporting infrastructure, relatively easier access to labour and know how. Canada – Ontario 1.15 CERI estimate. Considers the existence (Sarnia and Corunna) of an industrial hub with supporting infrastructure, however, access to labour and know how may be more challenging. South Korea 1.02 CERI estimate. Considers the existence of an industrial cluster in the Alberta, the presence of supporting infrastructure, access to labour and know how.
3 Compass International, 2018 4 ibid 5 ibid 6 The location factor is 0.92 if there is limited importation of equipment. However, CERI’s base case scenario for South Korea assumes elevated levels of equipment and construction materials import.
June 2019 Supply Costs and Emission Profiles of Petrochemical 47 Products in Selected Hubs
Cost Analysis Framework CERI evaluated the supply costs at the plant gate for greenfield projects constructed in Alberta, Ontario, USGC, and South Korea. The cost analysis was sub-divided into four evaluations to highlight the key factors affecting the supply costs for each facility in the petrochemical hubs studied. The evaluations apply to the plant gate supply cost given the criteria below:
• No carbon tax, no co-product sales (NCNC) • No carbon tax, with co-product sales (NCCS) • Carbon tax, no co-product sales (CTNC) • Carbon tax, with co-product sales (CTCS)
The inclusion of shipping (outbound transportation) costs for each evaluation yields the landed supply cost at the two destination markets considered in this study (USGC and China).
Considering the five feedstock scenarios (earlier indicated) and CERI’s cost analysis framework (CAF), a total of 80 supply cost model7 runs were performed in this study.
Figure 4.3 provides an overview of the four supply cost evaluations performed for the five feedstock types in Alberta, Ontario, USGC, and South Korea.
Figure 4.3: Supply Cost Analysis Framework
Source: CERI
Target Markets: The United States and China As the shipping/freight cost is usually absorbed by the PE and PP producer, CERI evaluated supply costs by considering that the PE and PP produced are landed at a destination market.
7 Twenty initial models were initially constructed and subsequently modified to test each of the CAF criteria shown in Figure 4.3.
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Two target markets were considered in this study. First, the US which was earlier presented in the feedstock and supply-demand sections of this report. Secondly, the Chinese market.
China’s base chemical capacity is expected to exceed 100 Mt by 2024, forming a major proportion of the Asia-Pacific combined chemical capacity of more than 200 Mt, the world-leading chemical capacity by 2024 (Figure 4.4). Despite their large percentage share of the global chemical capacity, the Asia-Pacific region is expected to have a PE deficit of ~27 Mt and ~10 Mt of PP by 2027 (Figure 2.21).
Figure 4.4: Global Base Chemical Capacity Forecast by Region
Source: CERI, 2018 (Modified)
For a region with a cumulative annual demand growth rate of 5.3% for PE and 4% for PP as at 2017 (Figure 2.21), China, the world’s largest chemical market (BASF 2018), is a logical target market for PE and PP products from the Middle East, North America and other Asia-Pacific net petrochemical product exporters such as South Korea (CERI 2016; also see Figure 4.4). Figure 4.5 shows China’s PP and PE demand-supply balances.
As shown in Figure 4.6, China’s potential 2.58 Mt of PE capacity outlook is second only to the US which has a world-leading new PE capacity of approximately 4.5 Mt due to the influx of cheap feedstock (primarily ethane) from shale gas fields.
June 2019 Supply Costs and Emission Profiles of Petrochemical 49 Products in Selected Hubs
Figure 4.5: China Demand-Supply Balance (‘000 tonnes)
2017 (estimate) 2016 (estimate) 2015
PP Supply
PP Demand
PE Supply
PE Demand
0 5000 10000 15000 20000 25000 30000 Source: ICIS - Widjaja and Tan, 2017.
Figure 4.6: New PE Capacities by Product, 2017 (‘000 tonnes)
Source: ICIS - Widjaja and Tan, 2017. Modified by CERI.
Note: HDPE = High-density PE, LDPE = Low-density PE, LLDPE = Linear low-density PE.
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June 2019 Supply Costs and Emission Profiles of Petrochemical 51 Products in Selected Hubs Chapter 5: Results
Feedstock options are designed to capture jurisdictional varieties of petrochemical feedstock demands and availability. Canadian petrochemical hubs in Alberta (AIH) currently use mainly ethane feedstock from NGL sources, whereas in Ontario there is some variety with about 30% ethane, 32% propane, 28% butane and about 10% naphtha. USGC feedstock blend comprises about 32% naphtha, 36% ethane, 18% propane, and some butane and gas oil. Naphtha is the only feedstock used by the South Korean petrochemical industry. Figure 5.1 shows the feedstock options utilized in the process model. LPG feed is assumed to be composed of 30% propane and 70% butane. Ethane-only, ethane and propane mix, LPG, and naphtha are feeds to the steam cracker (SC) while propane-only is feed to the PDH process.
Figure 5.1: Feedstock Compositions for Steam Cracking and Propane Dehydrogenation Processes
Ethane Propane Butane Naphtha
100%
90%
80%
70%
60%
50%
40% Feedstock Blend Feedstock 30%
20%
10%
0% SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Process Type Source: CERI
These feedstock and process combinations, in addition to their integrated polymerization units, constitute the five hypothetical facilities assessed for each of the four hubs of focus in our product supply cost modelling. Although some of the hubs (like Alberta and South Korean hubs) do not currently process all the feedstock options included here, our approach is designed to
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provide insights on the impacts of jurisdictional differences on economic and environmental performance indicators of the processing pathways considered.
Steam cracking (SC) of olefins and propane dehydrogenation (PDH) are the two primary processing pathways evaluated in this study. Oleflex and Catofin are the PDH technologies included for on-purpose polypropylene production. There are various steam cracking technologies available for processing various feedstock mixtures into olefins and co-products. CERI used data covering many olefin cracking technologies reported in industry reports, regulatory filings and academic literature.
Emission intensities of processing pathways capture the differences in processing technologies, fuel types, electricity requirements and sources. For instance, Catofin has a lower electricity requirement but higher fuel use, whereas Oleflex has lower fuel use but higher electricity requirement (Maddah 2018). On the basis of fuel use alone, Oleflex is less GHG emitting. However, on an overall energy requirement basis, Catofin generates fewer emissions. Figure 5.2 shows the ranges of GHG emissions for each process and feedstock combination. NGCC, coal and cogen are the three types of electricity sources incorporated in our current modelling, however, NGCC is used as the benchmark electricity source for most facilities. The process emissions include those from the production of olefin monomers and the subsequent polymerization step. Process emissions are expressed in per tonne of the primary/main product.
Figure 5.2: Ranges of Process GHG Emissions for Different Process and Feedstock Options
2.00
1.80
1.60
product) -
1.40
e/t 2
1.20
CO - 1.00
0.80
0.60
0.40
0.20 Process Emissions (t Emissions Process 0.00
Process and Feedstock Options
Source: CERI
June 2019 Supply Costs and Emission Profiles of Petrochemical 53 Products in Selected Hubs
The PDH process for on-purpose polypropylene has the lowest GHG emission intensity ranging between 0.19 to 0.62 t-CO2e/t covering both Oleflex and Catofin technologies. Polyethylene from ethane cracking plants has the next lowest intensity from 0.54 to 1.35 t-CO2e/t. Polyethylene from naphtha cracking has the highest GHG intensity ranging between 1.24 to 1.96 t-CO2e/t. However, naphtha cracking has a wider product spread relative to the other cracking feedstocks. Therefore, if overall emissions were to be allocated to all high-value products using any of the standard LCA methods (such as system expansion, substitution or partitioning), the intensities based on each high-value chemical would be lower. Nevertheless, our approach in this study is to quantify total processing emissions based on the main product for each feedstock processing pathway.
The primary sources of GHG emissions in a petrochemical plant are process heaters, boilers, cooling towers, catalyst regeneration vents, gas purge/flare systems, MSS (maintenance, start- up & shutdown) emissions, and process fugitives. Based on EPA prevention of significant deterioration (PSD) filings, fugitive emissions may account for up to 5% of total facility GHG emissions (Trinity Consultants 2012, 2012; US EPA 2014; Chevron Phillips 2018; US EPA 2012; Environmental Resources Management 2014). Depending on the process and technology in use, methane and nitrous oxide emissions account for between 0.1% to about 2% of total carbon dioxide equivalent emissions. In order to determine process chemistry emissions of methane and nitrous oxide, we calculate fuel and electricity emissions and then evaluate the difference between the latter and the total reported carbon dioxide equivalent emissions for similar processes, as listed in Appendices B and C.
In order to compare the effect of the electricity source on GHG emissions, Figure 5.3 shows the average process emissions for the three electricity sources considered. Average emissions are calculated for all the technology options available for processing the feedstocks into various products while meeting the heating and electricity requirements from various sources. Heating is provided by burning fuel gas, which is supplemented with natural gas when the fuel gas is insufficient. When cogen is used, some of the heating requirement is satisfied with the provision of high-pressure steam from the generator. CERI’s process model assumes cogen overall efficiency of 80% (40% electricity and 40% heat), consistent with industry reported information (AUC 2016; BASF 2019). NGCC efficiency of 55% is applied, along with supercritical coal efficiency of 40%.
Average process emissions are lowest in all the cases for PDH and propane feed, but highest for steam cracking and naphtha feed. For PE production, steam cracking and ethane feed processing has the lowest GHG emission intensity irrespective of electricity source. PDH using either coal or cogen has an average intensity of 0.52 or 0.26 t-CO2e/t. Steam cracking of either ethane or naphtha has intensities of about 0.90 or 1.60 t-CO2e/t (with coal power) and around 0.59 or 1.25 t-CO2e/t (with cogen), respectively.
On the basis of NGCC as the benchmark electricity source, electricity and fuel emissions for the various processing pathways represent, respectively, 27% and 73% for SC_Ethane, 51% and 49%
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for PDH_Propane, 14% and 86% for SC_Ethane+Propane, 14% and 86% for SC_LPG, or about 13% and 87% for SC_Naphtha.
Figure 5.3: Effect of Electricity Source on the Average GHG Emissions for Process and Feed Options
1.60
1.40 product)
- 1.20
e/t
2 CO
- 1.00
0.80
0.60
0.40
0.20 Average Process Emissions (t Emissions Process Average
0.00 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Coal+Heat NGCC+Heat Cogen
Source: CERI
We broadly categorized all products from the steam cracking reactor or the propane dehydrogenation reactor into the primary/main product, co-products, and side-products which are not valuable (i.e., not among the high-value chemicals). Depending on the process, the main product in our analysis is either ethylene or propylene. For steam cracking technologies, ethylene is the main product which is further polymerized into PE. For the PDH technologies, propylene is the main product polymerized into PP. Our supply cost model assumes that co-products are sold at their local market values. Figure 5.4 shows the co-products from each process and feed options included in our CAF scenarios for co-product sales.
The major co-products assessed include propylene (from steam cracking), ethylene (from PDH), methane and hydrogen (from both SC and PDH), in addition to others such as butadiene, butenes, and aromatics (benzene and toluene). The other side-products include carbon dioxide, carbon monoxide, nitrous oxide, nitrogen, oxygen, hydrogen sulphide, water, etc.
June 2019 Supply Costs and Emission Profiles of Petrochemical 55 Products in Selected Hubs
Apart from the co-products shown in Figure 5.4, the other co- and side-products represent about 4% of total product yields from ethane cracking, about 9% of the ethane-propane mix cracking, 13% of LPG cracking, 15% of PDH products and about 32% of naphtha feed cracking.
Figure 5.4: Selected Co-product Yields for Various Process and Feedstock Options
1.40
1.20
1.00
0.80
0.60
0.40
products (tonne per tonne of main main product)of tonne per (tonne products -
Co 0.20
0.00 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Propylene Methane Hydrogen Ethylene
Source: CERI
Supply Cost Results: PE and PP Supply Cost Framework, Plant Gate Based on the supply cost assessment performed using the CAF criteria discussed earlier, CERI’s SCM shows that plant gate supply costs are the highest in the CTNC evaluation (PE $1918/t; PP $1811/t), followed by NCNC (PE $1881/t; PP $1772/t). PE and PP supply costs are lower in the CTCS (PE $1398/t; PP $1601/t) and NCCS (PE $1361/t; PP $1562/t) assessments, with the NCCS being the least supply cost of the four CAF criteria evaluated.
Figure. 5.5 provides an overview of the plant gate supply costs from the cost analysis framework. The supply costs represent the average supply cost for the PE produced by all the petrochemical complexes evaluated in this study per CAF criteria. CERI’s engineering process model quantifies both the primary product and co-products from each petrochemical complex. For steam cracking,
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PE is considered as the primary product and PP is one of the co-products. For PDH, PP is the primary product and PE is one of the co-products. Therefore, the PP cost shown in Figure 5.5 was derived from the average PP supply cost from the four propane to PDH facilities modelled in this study.
Figure 5.5: Indicative Supply Costs per Cost Analysis Framework, Plant Gate (2018 Constant Dollars)
4000
3500
3000
2500
2000
1500 Supply Cost ($/t) Cost Supply 1000
500
0 NCNC NCCS CTNC CTCS
PE PP
Source: CERI
Supply Costs Per Feedstock Type and Jurisdiction, Plant Gate A more detailed breakdown of the supply costs based on the CAF criteria, feedstock type, and jurisdiction reveals informative supply cost differences as shown in Figures 5.6 to 5.9.
The NCNC supply costs (Figure 5.6) represent CERI’s supply cost estimates without the effect of carbon taxes and revenue generated from selling co-products. Therefore, the NCNC CAF results capture the jurisdictional impacts of constructing and operating the petrochemical facilities in Alberta, Ontario, USGC, and South Korea. The impacts observed from considering just co-product sales (NCCS) or carbon tax (CTNC) are represented respectively in Figures 5.7 and 5.8, while Figure 5.9 depicts the combined effects of both carbon tax and co-product sales on supply costs. The results indicate that the supply cost is most sensitive to the value of co-products. A carbon tax has the most impact on Canadian and South Korean supply costs, relative to USGC where there is no carbon tax. Overall, a carbon tax has the most impact on Canadian supply costs despite the predominant processing of the lower GHG-intensity gas-based feedstocks in Canadian petrochemical hubs. Thus, this stems from the higher price of carbon dioxide equivalent emissions in Canada, compared to the other jurisdictions.
June 2019 Supply Costs and Emission Profiles of Petrochemical 57 Products in Selected Hubs
Availability of cheaper NGL feedstocks in producing areas such as Alberta and USGC results in lower PE supply costs for ethane and ethane+propane cracking plants. In the absence of a carbon tax, PP supply costs at Canadian and USGC facility gates are quite similar – albeit, slightly higher for USGC plants but more pronounced for a South Korean plant due to feedstock cost. Moreover, while LPG processing would be unfavourable in South Korea on economic terms, naphtha processing is most competitive relative to the other hubs. The supply costs are also presented by jurisdiction in Appendix D.
Figure 5.6: Indicative NCNC Supply Costs per Jurisdiction and Feed Type, Plant Gate (2018 Constant Dollars)
4500 4000 3500 3000 2500 2000
1500 Supply cost ($/t) cost Supply 1000 500 0 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
AB ON USGC South Korea
Source: CERI
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Figure 5.7: Indicative NCCS Supply Costs per Jurisdiction and Feed Type, Plant Gate (2018 Constant Dollars)
4500 4000 3500 3000 2500 2000
1500 Supply cost ($/t) cost Supply 1000 500 0 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
AB ON USGC South Korea
Source: CERI
Figure 5.8: Indicative CTNC Supply Costs per Jurisdiction and Feed Type, Plant Gate (2018 Constant Dollars)
4500 4000 3500 3000 2500 2000 1500
Supply cost ($/t) cost Supply 1000 500 0 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
AB ON USGC South Korea
Source: CERI
June 2019 Supply Costs and Emission Profiles of Petrochemical 59 Products in Selected Hubs
Figure 5.9: Indicative CTCS Supply Costs per Jurisdiction and Feed Type, Plant Gate (2018 Constant Dollars)
4500 4000 3500 3000 2500 2000
1500 Supply cost ($/t) cost Supply 1000 500 0 SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
AB ON USGC South Korea
Source: CERI
Given that our supply cost model has the plant utilization factor ramping from 70% in the first year, 80% in the second year and 90% afterwards, we also assessed the sensitivities of our results to plant utilization at a 35% level in the first operating year. For PP production in each hub, the average impact on supply cost is +$20/t (AB), +$20/t (ON), +$21/t (USGC), and +$21/t (South Korea). For PE production in each hub, the average impact on supply cost is +$13/t (AB), +$15/t (ON), +$12/t (USGC), and +$19/t (South Korea). Overall average impact on PP supply cost due to the lower plant utilization across hubs of 35% is +$21/t, whereas for PE it is +$15/t.
Key Supply Cost Components From CERI’s analysis, the key components affecting PE supply costs are feedstock cost (75.19%), capital cost (9.26%), and operating costs (10.19%). Other components such as electricity and corporate tax contribute 0.76% and 1.95%, respectively. Similarly, as for PP, the key elements are feedstock cost (77.47%), capital cost (12.46%), and operating costs (3.52%). Electricity and corporate tax contribute 1.99% and 2.51%, respectively.
A carbon tax increases the supply cost by an overall impact of 1.53% and 1.57% for PE and PP, respectively. In the CTCS CAF scenario, the overall impact of a carbon tax on the supply cost is moderated because of the revenue generated from co-product sales. Figures 5.10 and 5.11 show the breakdown of supply cost elements for PE and PP, respectively, across the four petrochemical hubs.
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Figure 5.10: Supply Cost Structure for PE Production at the Four Hubs
June 2019 Supply Costs and Emission Profiles of Petrochemical 61 Products in Selected Hubs
Figure 5.11: Supply Cost Structure for PP Production at the Four Hubs
The average revenue share from hydrogen sales from PE production across the four hubs is 14.06% while the average revenue share from propylene sales is 15.61%. Average revenue share from hydrogen sales from PP production via PDH is 11.63%. Ethylene co-production from PDH amounts to about 0.0015 tonne per tonne of propylene main product. Naphtha yields about 10% aromatics, including benzene and toluene. Our current supply cost numbers are not net of the aromatics yields.
Figure 5.12 shows the indicative revenue shares of propylene and hydrogen co-product sales for PE and PP production from their respective feedstock options. Ethylene constitutes about 0.1% of the co-product revenue shares from PDH plants in the 4 jurisdictions, which amounts to a reduction in the supply cost of up to $1.5/t in 2018 constant dollars.
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Figure 5.12: Shares of Hydrogen and Propylene Co-product Sales for Each Processing Pathway
Landed Supply Costs The landed supply costs provide a perspective of the indicative supply costs at the destination market for produced PE and PP using the five feed options and transported to the USGC or China for sale. The SFC ($/t) is added to the supply costs obtained for each of the CAF assessments to obtain the supply cost at the destination market. CERI’s SFC estimates were based on information available in the public domain, as well as feedback from CERI interviews with petrochemical industry experts.
Table 5.1 shows the base case SFC costs for transporting PE and PP from the four petrochemical hubs to the USGC and China. CERI’s base case SFC is based on the average between the low and high SFC (shown in Appendix A). Canadian hubs have the advantage to ship to China against USGC, and the advantage to shipping products to USGC against South Korean.
Table 5.1: PE and PP Outbound Average Transportation Costs (base case)
USGC (Texas) China PE PP PE PP Origin $/t $/lb $/t $/lb $/t $/lb $/t $/lb Alberta 13 0.006 18 0.008 23 0.010 28 0.013 Ontario 14 0.006 19 0.009 26 0.012 30 0.014 USGC 8 0.003 11 0.005 31 0.014 35 0.016 South 26 0.012 29 0.013 18 0.008 22 0.010 Korea
June 2019 Supply Costs and Emission Profiles of Petrochemical 63 Products in Selected Hubs
A further break down of the SCM results are presented in Appendix D.
If we take the average supply cost across all the hubs, for each process and feedstock option under the NCNC scenario, the economic and environmental performance indicators of each feedstock processing pathway can be visualized and compared – as in Figure 5.13 – with reduced effects of jurisdictional differences on the cost for each process and feedstock combination.
Processes using gas-based feedstocks have lower emissions and supply costs as against LPG and naphtha, which have higher energy requirements. For the PE and PP production studied here, steam cracking of ethane feed and propane dehydrogenation have the lowest economic and GHG emission intensities relative to the other production pathways.
Figure 5.13: Average Supply Cost and GHG Emissions by Process and Feedstock Options
Our analysis boundary does not cover upstream emissions from natural gas and NGL supply chains, so this comparison should be taken in this context. There is still an active debate in the literature about relative upstream intensities of gas against oil, and conventional versus unconventional resources (Umeozor et al. 2018; Yeh et al. 2017; Zavala-Araiza et al. 2018; Johnson et al. 2017; Barkley et al. 2017; Laurenzi et al. 2016; Kasumu et al. 2018).
Considering the compositions of processing capacities in the four petrochemical hubs studied here, CERI can estimate their total annual GHG emissions at defined utilization levels. In consonance with our supply cost modelling assumption, we apply 90% capacity utilization factor
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to the most recently available data on processing capacities at the hubs as reported by (Koottungal 2015) and (Morse 2017). By combining the ranges of emission intensities of each processing pathway with the total products generated therein, CERI evaluated total annual emissions in each hub, as shown in Figure 5.14.
Total annual GHG emissions are highest for USGC, in the range of 19.8 Mt CO2e to 37.4 Mt CO2e. Seconded by South Korean hubs with emissions ranging between 6.0 Mt CO2e and 9.5 Mt CO2e. Canadian petrochemical hubs have the lowest annual GHG emissions with the Ontario hub emitting between 0.5 Mt CO2e to 0.9 Mt CO2e, whereas the Alberta hub emits between 2.1 Mt CO2e to 5.2 Mt CO2e.
Figure 5.14: Total Annual GHG Emissions from Petrochemical Hubs (2016 capacity basis)
US GC
S.Korea
ON
AIH
0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000
Total Annual GHG emissions (kt-CO2e)
June 2019 Supply Costs and Emission Profiles of Petrochemical 65 Products in Selected Hubs Chapter 6: Conclusions
This study investigated economic and GHG emissions attributes of petrochemical processing pathways using steam cracking and propane dehydrogenation, integrated with polymerization units. Five feedstock options including single and mixed feedstocks such as ethane, propane, ethane and propane, LPG (propane and butane), and naphtha which are used to produce olefins and various co-products were analyzed using supply cost and GHG intensity as performance criteria.
CERI used a process data-based model to quantify feedstock consumption for each processing pathway, product yields for the main/primary products and co-products, process energy requirements including heating and electricity, and GHG emissions from the processing operations, including CO2, N2O, and CH4. GHG emissions from petrochemical facilities depend on the types of fuel in use, feedstock processed, and process/technology design and operational attributes. Fugitive emissions are also of concern for petrochemical plants due to the variety of potential sources of leakage. However, fugitive emissions are smaller in comparison to energy use emissions. Furthermore, non-CO2 GHG emissions typically account for less than 1% of total carbon dioxide equivalent emissions.
We also calculated indicative plant gate supply costs under each processing pathway, assuming that hypothetical polyethylene and polypropylene integrated facilities are located in four petrochemical hubs in Alberta, Ontario (Sarnia/Corunna), US Gulf Coast and South Korea. Using market information on current and anticipated demand growth regions, CERI selected the US and China as potential destination markets for the products. Supply costs at the destination markets are also calculated on a FOB basis in order to assess the competitiveness of products from each petrochemical hub at the destination markets.
By observing jurisdictional explicitness in the modelling input parameters, the cost of constructing and operating each plant in the selected hubs are evaluated. Among the important supply cost modelling variables are capex, opex, feedstock cost, revenues from the primary product and co-product sales, carbon tax, and transportation costs to move products to the destination markets.
Alberta and USGC hubs have the advantage of cheaper NGL feedstock due to their location, and as such PE is produced in these areas at the lowest supply costs. Feedstocks are relatively more expensive in Ontario and South Korea. Even with a carbon tax in Alberta, plant gate cost of PE production from ethane feed is lower than in USGC despite not having a carbon tax.
The observation is different in the case of propylene and PP from PDH due to the current abundant supply and ease of moving propane to various demand locations. Plant gate PP supply costs are similar across the four hubs, although slightly cheaper in Canada. This signifies that competitive landing costs at destination markets would be crucial for all volumes destined for export.
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Canada currently exports about 85% of annual propane production and imports PP for the local plastics market. Thus, there is an existing and growing domestic PP demand to fulfill. The two ongoing PDH projects by Inter Pipeline and CKPC in Alberta will together produce about 630 KTA of PP for the local market. Of this volume, Inter Pipeline will contribute about 80 KTA and sell the rest of its product in the form of propylene under a service contract with North American Polypropylene. When completed, these two projects will leave about 124 Mbpd of propane for export. Depending on the development of additional export terminals, the future supply-demand balance for propane in western Canada is challenging to predict. The balance is further complicated by the source supply for any new west coast LNG projects. If more PP demand opportunities arise in proximate markets, Alberta may have the ability to add more PDH capacity.
Relative to other jurisdictions, the Canadian petrochemical sector predominantly utilizes gas- based feedstocks. However, this is now a growing trend in other areas with the abundance of NGLs mainly from shale and tight reservoirs. In these hubs, gas-based feedstocks offer both economic and environmental advantages. Companies using gas-based feedstocks have witnessed wider margins as costs have stayed quite low while revenues have followed oil prices. Processing lighter feedstocks also generates less GHG emissions. The availability of natural gas is also driving the growth of gas power plants, reducing the carbon emissions of electricity grids if coal is displaced. The combined effect is a lowering of GHG intensity products from the petrochemical industry.
Yet, there are other issues like plastics pollution which face the industry. If these challenges instigate major global policy efforts to regulate the impacts of various petrochemicals processing end-use products, recycling could become an essential environmental impact mitigation option. However, careful consideration is needed to determine if there are net energy penalties from the recycling operations and the availability of commercial-scale technologies to reintegrate plastic wastes. The IEA estimates that recycling will result in about 9% reduction in emissions in their future scenarios (IEA 2018).
Social, political and regulatory uncertainties are growing sources of concern for the industry. Recently, the Canadian government announced a ban on single-use plastics. Canada has also proposed a Clean Fuels Standards (CFS) regulation under the Canadian Environmental Protection Act 1999, to reduce GHG emissions from fuel use across various economic sectors (including the petrochemicals industry). The CFS policy is designed to use a lifecycle approach in quantifying the emissions from fuels used for heating, electricity and transportation in the affected sectors. CERI’s recent study on fuel decarbonization estimated various cost impacts for gaseous, liquid and solid fuels under different decarbonization scenarios ranging from $0.94 per GJ to $3.51 per GJ (CERI 2019). If implemented, this may erode the current feedstock pricing advantage available to Canadian petrochemical hubs – particularly Alberta – since the additional costs would be passed down to buyers and users of the affected products and services. Other impending issues that may affect feedstock pricing, demand and supply are tightening International Maritime Organization (IMO) fuel standards, crude oil-to-chemicals process innovations, and peak oil demand.
June 2019 Supply Costs and Emission Profiles of Petrochemical 67 Products in Selected Hubs
In the meantime, stakeholders and operators can focus on the cost-effective options for improvements such as design and operational energy efficiency levers, feedstock switching, electrification of process systems, digitalization, and implementation of facility survey programs to identify and plug any GHG leaks.
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June 2019 Supply Costs and Emission Profiles of Petrochemical 69 Products in Selected Hubs Bibliography
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June 2019 Supply Costs and Emission Profiles of Petrochemical 77 Products in Selected Hubs Appendix A: Economic Modelling Data
Table A.1: Supply Cost Model Input Parameters and Assumptions
Jurisdiction Alberta Industrial Heartland Ontario – Sarnia/Corunna
Feedstock Ethane - Ethane + LPG-only Naphtha Propane Ethane - Ethane + LPG-only Naphtha Propane only Propane (PDH) only Propane (PDH) OPEX inflation (%) 2 Feedstock price ($/gal) 0.121 0.50 0.78 1.92 0.66 0.572 0.812,3 1.11 1.61 0.91 2 Feedstock price inflation (%) 2
Discount rate (%) 102 4 2 Plant utilization (%) 70% (1st yr.), 80% (2nd yr.), 90% (rest) 2 CAPEX allocation/year during 20% (1st yr.), 30% (22nd yr.), 50% (3rd yr.) the plant build-out 2 2 Note: All dollar references are in $US. 2 2
2 2 2 2 2 2 2 2
2
1 Source for Alberta feedstock prices: Sproule Associates, 2019 2 Source for Ontario ethane, LPG and Naphtha feedstock: (IEA 2018); 2016 Asia Pacific estimates converted to 2018 dollars. 3 Source for ethane + propane and propane (PDH) feedstocks: NEB, 2019. 4 CERI’s discount rate is consistent with the discount rate reported in the literature (Ren, et al. 2008; Andre et al. 2012) for cost-assessing similar petrochemical plants. June 2019 78 Canadian Energy Research Institute
Jurisdiction United States Gulf Coast South Korea
Feedstock Ethane - Ethane + LPG-only Naphtha Propane Ethane - Ethane + LPG-only Naphtha Propane only Propane (PDH) only Propane (PDH) OPEX inflation (%) 2 Feedstock price ($/gal) 0.355 0.726 0.75 1.427 0.89 0.848 0.939 2.6510 1.24 0.97 2 Feedstock price inflation (%) 2
2 Discount rate (%) 102 Plant utilization (%) 70% (1st yr.), 80% 2(2 nd yr.), 90% (rest) 2 CAPEX allocation/year during 20% (1st yr.), 30% (2nd yr.), 50% (3rd yr.) 2 the plant build-out 2
Note: All dollar references are in $US. 2 2
2 2
2 2
2 2
2 2
2
5OPIS, 2019 6Sproule Associates 2019. 7Trading Economics, 2019. 8Source for South Korea ethane, and naphtha prices: (IEA 2018); 2016 estimates converted to 2018 dollars. 9Source for South Korea ethane + propane and propane prices: (IEA 2018) 10https://www.globalpetrolprices.com/lpg_prices/ June 2019 Supply Costs and Emission Profiles of Petrochemical 79 Products in Selected Hubs
Table A.2: Indicative SCM Results for Alberta and Ontario Petrochemical Facilities at Plant Gate (2018 Constant Dollars)
Jurisdiction Alberta Industrial Heartland Ontario – Sarnia/Corunna
Feedstock Ethane - Ethane + LPG-only Naphtha Propane Ethane - Ethane + LPG-only Naphtha Propane only Propane (PDH) only Propane (PDH) Supply cost ($/t) 1754 1774 990 1189 1108 1736 1756 985 1196 1100 Construction period (yrs.) 3 Facility lifetime (yrs.) 30 3 Plant capacity (mtpa) 1.50 1.50 0.75 1.45 0.525 1.50 1.50 0.75 1.45 0.525 30 Project CAPEX ($ billion) 7.84 7.97 2.16 2.75 3.50 3 7.84 7.97 2.16 2.875 3.50 OPEX ($/t) 322 329 179 313 151 30 322 328 179 327 151 3 Cash cost ($/t) 686 688 606 614 625 668 670 601 608 617 30 3
30 3 30 3 30 3 30 3 30 3 30
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Table A.3: Indicative SCM Results for USGC and South Korea Petrochemical Plants (2018 Constant Dollars)
Jurisdiction USGC - Texas South Korea
Feedstock Ethane - Ethane + LPG-only Naphtha Propane Ethane - Ethane + LPG-only Naphtha Propane only Propane (PDH) only Propane (PDH) Supply cost ($/t) 1768 1069 924 843 799 1711 1736 975 1107 1080 Construction period (yrs.) 3 Facility lifetime (yrs.) 30 3 Plant capacity (mtpa) 1.50 1.50 0.75 1.45 0.525 1.50 1.50 0.75 1.45 0.525 30 Project CAPEX ($ billion) 7.84 7.97 2.16 2.75 3.50 3 7.84 7.97 2.16 2.875 3.50 OPEX ($/t) 337 322 180 216 148 30 314 323 174 275 145 3 Cash cost ($/t) 670 575 575 575 575 666 668 600 604 615 30 3 30 Table A.4: Current and Anticipated Jurisdictional Carbon3 Tax ($/tCO2e) 30 2018 2019 2020 2021 20223 2023 2024 2025 Alberta 24 32 32 32 40 40 40 40 30 Ontario 16 32 32 32 40 40 40 40 South Korea 21 21 21 21 2130 21 21 21 USGC 0 0 0 0 03 0 0 0 30 3 30
June 2019 Supply Costs and Emission Profiles of Petrochemical 81 Products in Selected Hubs Appendix B: Process Input-Output Data
Table B.1: Sample Steam Cracking Feedstocks, Side- and Co-products, Energy Use and Emissions Data (kg-product per kg-feedstock)
Description Ethane Propane Naphtha Ethylene 0.803 0.465 0.324 Propylene 0.016 0.125 0.168 Process Energy Use1 0.3142 0.249 0.264 Steam Cracker Fuel (PJ) 16.5 9.4 11.3 Methane Produced 0.061 0.267 0.139 Hydrogen Produced 0.060 0.015 0.011 CO2 Emissions (MtCO2) 0.34 0.57 0.55 Source: (Griffin, Hammond, and Norman 2018)
Table B.2: Naphtha Steam Cracker Yields (kg-product per kg-feedstock)
Product Yield % Ethane (C2) Propane (C3) Butane (C4) Naphtha (C5+) Ethylene 0.8 0.4 0.36 0.23 Propylene 0.03 0.18 0.2 0.13 Butylene 0.02 0.02 0.05 0.15 Butadiene 0.01 0.01 0.03 0.04 Fuel Gas 0.13 0.38 0.3 0.26 Py Gasoline 0.01 0.01 0.06 0.17 Gas Oil 0 0 0 0.02 Total 1 1 1 1 Source: (Jones, Laroche, and Ginyard-Jones 2016)
1 Amount of the feedstock used as fuel 2 For ethane, only 80% of fuel is ethane – supplemented with natural gas
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Table B.3: Primary and Final Energy Requirements of Petrochemical Processes
In Final Energy Terms (GJf/t) In Primary Energy Terms (GJp/t)
Process Electricity Feedstock Fuel Steam Total Electricity Feedstock Fuel Steam Total Ethylene (Steam 0.3 45 18.1 -1.4 62 0.7 45 18.1 -1.5 62.3 cracking) Propylene (steam 0.3 45 13.1 -1.4 57 0.7 45 13.1 -1.5 57.3 cracking) Propylene (FCC) 0.1 45 2 47.1 0.1 45 2.2 47.3
Polyethylene, high 0.9 1 1.9 2.2 1.1 3.3 density (HDPE) Polyethylene, low 3.5 -2.1 1.4 8.8 -2.4 6.4 density (LDPE) Polyethylene, 0.4 1.6 2 1.1 1.8 2.9 linear low density (LLDPE) Polyethylene 0.7 4.1 4.8 1.8 4.1 5.9 terephthalate (PET) Polypropylene (PP) 0.9 0.1 1 2.2 0.1 2.3
Polystyrene (PS) 0.4 0.5 0.9 1 0.5 1.5
Polyvinyl chloride 0.6 0.5 1.2 2.3 1.6 0.5 1.4 3.5 (PVC) Synthetic rubber & 2.5 19.9 22.4 6.2 22.1 28.3 latex Total 10.6 135 32.2 25 202.8 26.4 135 32.2 27.4 221
Source: IEA, 2009, Modified by CERI
June 2019 Supply Costs and Emission Profiles of Petrochemical 83 Products in Selected Hubs Appendix C: Existing Facility Inventory
Table C.1: Petrochemical Facilities in Alberta, Ontario, USGC and South Korea
Location Product Feedstock Process/ Plant CO2 (tpy) CH4 (tpy) N2O (tpy) Technology Capacity (kT/yr) AB LDPE, EVA Ethylene 143 127291.00 4.05 501.83
LLDPE Ethylene 500 38717.61 17.92 0.10
LLDPE Ethylene 859 1026360.37 105.55 11.53
Ethane 1285
LAO Ethylene Oligomerization 250 165697.86 4.52 4.18 Process MEG Ethylene 350
EO/EG Ethylene 310
EO/EG Ethylene 285
Ethylene Ethane 726 3064835.55 323.46 48.05
Ethylene Ethane 816
Ethylene Ethane 1270
LLDPE Ethylene 1112
LLDPE & Ethylene 431 HDPE styrene Benzene 450 832724.59 345.45 8.11 monomer MEG, EO/EG Ethylene 450
PGP SGL 68
ON Ethylene C2, C3, C4, C5+ 300 271712 25 5
HDPE Ethylene 470
Butyl Rubber Styrene 150 11665.6 19.8 0.13
Ethylene C2, C3, C4, C5+ 839 992166.999 432.117 11.046
HDPE, LLDPE Ethylene SCLAIRTECH™ 204 technology HDPE Ethylene NOVAPOL 211 49911 2 1 processing technology LDPE Ethylene NOVAPOL 170 processing technology Styrene Ethylene 431 107113 8 1 monomer
USGC Ethylene Naphtha AspenTech 860 1645557.3 503.46 38.308
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Propylene Naphtha AspenTech 860
Ethylene, PE C2, C3, C4, C5 AlphaPlus® 1,500 normal Ethylene C2, C3, C4, 855 1849883.9 256.91 33.618 Naphtha Ethylene - 1,950 1330941.3 230.68 21.787
Ethylene Ethane, Propane 630 3427350.3 4629.27 8.045
Ethylene C2, C3, Naphtha 1,010
Ethylene Ethane, Propane 520 2356681 4482.7 33.637
Ethylene C2, C3, Naphtha 740
Ethylene C2, C3, Naphtha 590
Ethylene - 410
Ethylene Ethane CB&I's SRT® 680 848337.5 481.77 5.197
Ethylene C2, C3, C4, 781 2388186 390.09 14.187 Naphtha Ethylene Ethane, Naphtha 875 350941.4 10.83 1.817
Ethylene Ethane, Naphtha 875
Ethylene C1, C2, Naphtha 771 522040.4 321.36 33.612
Ethylene C1, C2, Naphtha 1,189 1070675.6 130.3 16.426
Ethylene C1, C2, C3, Naphtha, gas oil, residue 1,000 86690.2 2.685185 0.413 185 Ethylene C1, C2, C3, Naphtha, gas oil 2,200 10024900 915.65 83.186
Ethylene C1, C2, C3, Naphtha, gas oil 900 5913437.8 618.42 40.328
Ethylene Ulsan 634 963782 195.58 21.868
Ethylene Ethane, Propane, Naphtha 816 3703562.8 367.9 25.655
Ethylene Ethane, Propane, Naphtha 725
Ethylene - 180 1226556.1 166.72 12.659
Ethylene Ethane, Propane, Naphtha 1,752 2211835.2 238.01 25.953
Ethylene Gas 151 40926.8 58.82 0.067
Ethylene Ethane 471 771012.7 14.55 1.941
Ethylene - 1,179 4139973.2 594.77 37.326
Ethylene Ethane, Naphtha, gas oil 1,451 897494.5 16.91 2.071
Ethylene Ethane 567 193580 5.01 0.71
Ethylene Ethane, Propane 630
Ethylene Ethane, Propane 884 777950.8 8.59 0.859
USGC Propylene Propane Total 748 1,289,357 57 8
Reactor charge Heater 280,168 12.99 2.54
Waste Heat Boiler Burner 19,522 0.98 0.2
Regeneration Air Heater 650,704 23.89 4.25
Regen Air Comp. Gas Turbine A 124,897 2.32 0.23
Regen Air Comp. Gas Turbine B 124,897 2.32 0.23
VOC from Reactors 5,580
Coke Burn 60,000
June 2019 Supply Costs and Emission Profiles of Petrochemical 85 Products in Selected Hubs
Auxiliary Boiler 16,321 0.82 0.16
Process Fugitives 0.25
Nat. Gas Pipeline Fugitives 13.04
Process Flare, Routine 2,818 0.04 0.01
Process Flare, MSS 4,426 0.16 0.03
Fire Water Pump Engine 16 0.0007 0.0001
Raw Water Pump Engine 8 0.0003 0.0001
USGC ethylene Ethane Total 1500 2,208,353 140 27
Steam Cracking Furnaces (8) 206,000 11.9 2.4
VHP Boiler 127,000 6.5 1.1
VDU 2,400 0.046 0.0046
Low Profile Flare 27,000 2.1 0.42
Emergency Generator Engines 274 0.011 0.002
Fugitive Process Emissions
West ethylene, Ethane Total 1,176,671 78 12 Virginia Propylene, polyethylene Pyrolysis 565,453 38.2 10.63 Furnaces – Normal Operation (5) 36,567 2.29 0.64
Thermal Oxidizer Burner 66,988 1.28 0.36
Cracker Process - Oxidizer 489,307
Main Flare Pilot (2) 423 0.008 0.008
Ethylene Storage Flare Pilot (2) 206 0.004 0.004
Cracker Storage Flare Pilot (2) 206 0.004 0.004
Oxygen Flare Pilot (2) 103 0.002 0.002
Ethane Cracker Plant Fugitives 121
ethylene, Propylene, polyethylene RTO Burner 10,306 0.2 0.19
PE Process – Oxidizer 1,632
PE Plant Fugitives and Flares 35.6
Low-Pressure Flare Pilot (2) 206 0.004 0.004
Catalyst Activator 5,153 0.099 0.094
USGC Ethylene Ethane Total 300,694 132 176
Cracking Furnace 300400 119 176
Decoking Pot 281
OP2 Fugitives 13 13
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USGC Ethylene Ethane Total 641,492 18 2
Cracking Furnaces (5) 278,357 5.19 0.52
Cracking Furnaces (3) 301,855 5.63 0.56
Low Pressure Flare, 14,034 0.22 0.02
Pressure-Assisted Flare, 43,910 2.13 0.42
TOX 3,320 0.06 0.007
Process Area Fugitives 0.02 3.82
Cooling Tower 1 CT-936 Heat Exchanger System Backup Diesel& Generators (2) 16 0.001 0.0001
South Ethylene Naphtha 700 Korea Ethylene Naphtha 320
Ethylene Naphtha 450
Ethylene Naphtha 760
Ethylene Naphtha 600
Ethylene Naphtha 820
Ethylene Naphtha 545
Ethylene Naphtha 185
Ethylene Naphtha 480
Ethylene Naphtha 420
Ethylene Naphtha 350
Source: (Government of Ontario 2019b; ECCC 2016, 2019; US EPA 2018; Koottungal 2015; Trinity Consultants 2012; US EPA 2012, 2014; Environmental Resources Management 2014; Dow Chemical Company 2014; Enterprise Products Operating LLC 2012; CERI 2016)
June 2019 Supply Costs and Emission Profiles of Petrochemical 87 Products in Selected Hubs
Figure C.1: Alberta Olefin Cracking Feedstock
0%
Ethane
Propane
Butane
100% Naphtha
Gas Oil
Other
Figure C.2: Ontario Olefin Cracking Feedstock
10% 0%
30%
28% Ethane Propane Butane
32% Naphtha Gas Oil Other
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Figure C.3: USGC Olefin Cracking Feedstock
7% 3% Ethane
36% Propane Butane 32% Naphtha
Gas Oil 4% 18% Other
Figure C.4: South Korea Olefin Cracking Feedstock
0%
Ethane Propane Butane Naphtha 100% Gas Oil Other
June 2019 Supply Costs and Emission Profiles of Petrochemical 89 Products in Selected Hubs Appendix D: Further Breakdown of Results
Table D.1: Lower Range of Outbound Transportation Costs for PE and PP
Polymer Product (Low) PE PP PE PP USGC (Texas) China Origin $/t $/lb $/t $/lb $/t $/lb $/t $/lb Alberta 12 0.005 15 0.007 20 0.009 23 0.010 Ontario 13 0.006 16 0.007 21 0.010 25 0.011 USGC 5 0.002 8 0.004 27 0.012 30 0.014 South 21 0.010 23 0.010 15 0.007 18 0.008 Korea
Table D.2: Upper Range of Outbound Transportation Costs for PE and PP
Polymer Product (High) PE PP PE PP USGC (Texas) China Origin $/t $/lb $/t $/lb $/t $/lb $/t $/lb Alberta 14 0.006 20 0.009 25 0.011 33 0.015 Ontario 15 0.007 22 0.010 30 0.014 35 0.016 USGC 10 0.005 14 0.006 34 0.015 40 0.018 South 30 0.014 35 0.016 21 0.010 25 0.011 Korea
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Figure D.1: Indicative Supply Costs by Jurisdiction – NCNC
4500
4000
3500
3000
2500
2000
Supply cost ($/t) cost Supply 1500
1000
500
0 AB ON USGC South Korea
SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Figure D.2: Indicative Supply Costs by Jurisdiction – NCCS
4500
4000
3500
3000
2500
2000
Supply cost ($/t) cost Supply 1500
1000
500
0 AB ON USGC South Korea
SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
June 2019 Supply Costs and Emission Profiles of Petrochemical 91 Products in Selected Hubs
Figure D.3: Indicative Supply Costs by Jurisdiction – CTCS
4500
4000
3500
3000
2500
2000
Supply cost ($/t) cost Supply 1500
1000
500
0 AB ON USGC South Korea
SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
Figure D.4: Indicative Supply Costs by Jurisdiction – CTNC
4500
4000
3500
3000
2500
2000
1500 Supply cost ($/t) cost Supply 1000
500
0 AB ON USGC South Korea
SC_Ethane PDH_Propane SC_Ethane+Propane SC_LPG SC_Naphtha
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