Part B: Project Description - Alberta€¦ · Northern Lights Upgrader Project Part B September 29,...

Northern Lights Upgrader Project

Part B: Project Description


Part B September 29, 2006 Page i

Table of Contents

Page TABLE OF CONTENTS..................................................................................................... i LIST OF TABLES.............................................................................................................. v LIST OF FIGURES............................................................................................................vi B PROJECT DESCRIPTION................................................................................1

B.1 Project Overview ...............................................................................................1 B.1.1 Upgrader................................................................................................4 B.1.2 Infrastructure, Utilities And Offsites .......................................................4 B.1.3 Site Selection.........................................................................................5

B.2 Need For And Purpose Of The Project .............................................................5 B.2.1 Need For The Project ............................................................................5 B.2.2 Benefits Of The Project..........................................................................6 B.2.3 Economic Viability..................................................................................7 B.2.4 Schedule And Timing.............................................................................8

B.3 Upgrading..........................................................................................................8 B.3.1 Overview................................................................................................8 B.3.2 Primary Upgrading.................................................................................8 B.3.3 Secondary Upgrading ..........................................................................12 B.3.4 Air Separation Unit...............................................................................14 B.3.5 Asphaltene Gasification And Hydrogen Purification ............................14 B.3.6 Sulphur Recovery Complex .................................................................15 B.3.7 Supporting Utility Systems...................................................................19 B.3.8 Upgrader Product ................................................................................19 B.3.9 Material And Energy Balances ............................................................20

B.4 Infrastructure ...................................................................................................20 B.4.1 Overview..............................................................................................20 B.4.2 Site Preparation ...................................................................................26

B.4.2.1 Demolition.......................................................................................27 B.4.2.2 Concrete Batch Plant......................................................................27

B.4.3 Transportation......................................................................................29 B.4.3.1 Roads .............................................................................................29

B.4.3.1.1 Construction Access .....................................................................29 B.4.3.1.2 Upgrading Of Access Roads And Intersections ............................29

B.4.3.2 Rail..................................................................................................31 B.4.4 Temporary Infrastructure Tie-Ins .........................................................36 B.4.5 Buildings ..............................................................................................36

B.4.5.1 Temporary Construction Management Buildings............................36 B.4.5.2 Administration And Maintenance Buildings ....................................36


Part B September 29, 2006 Page ii

B.4.5.3 Utilities Buildings.............................................................................38 B.4.5.4 Process Buildings ...........................................................................39

B.5 Utilities And Offsites ........................................................................................40 B.5.1 Overview..............................................................................................40 B.5.2 Water And Water Treatment................................................................44

B.5.2.1 Water Demand And Supply ............................................................44 B.5.2.1.1 Demand.........................................................................................44 B.5.2.1.2 Supply Sources.............................................................................45 B.5.2.1.3 Demand/Supply Summary ............................................................49 B.5.2.1.4 Raw Water (River) Intake And Pipeline System Description.........49 B.5.2.1.5 Raw Water Consumption ..............................................................51

B.5.2.2 Water Management And Treatment ...............................................52 B.5.2.3 Potable Water Supply And Distribution...........................................54 B.5.2.4 Boiler Feedwater/Condensate/Service Water Treatment ...............54

B.5.2.4.1 Service Water................................................................................54 B.5.2.4.2 Boiler Feedwater/Condensate.......................................................57 B.5.2.4.3 Chemical Feed..............................................................................57

B.5.2.5 Process Cooling Water And Cooling Tower ...................................58 B.5.2.5.1 Process Cooling Approach............................................................58

B.5.2.6 Ponds..............................................................................................60 B.5.2.7 Overall Water Balance....................................................................61

B.5.3 Wastewater..........................................................................................62 B.5.3.1 Domestic/Sanitary Wastewater Management.................................63 B.5.3.2 Industrial Wastewater Management And Treatment ......................65 B.5.3.3 Stormwater Management ...............................................................66

B.5.4 Fuel Gas Supply And Distribution........................................................67 B.5.4.1 Natural Gas Demand ......................................................................67 B.5.4.2 Natural Gas Supply And Distribution ..............................................68

B.5.5 Steam And Power Demand .................................................................71 B.5.6 Electric Power Supply And Distribution ...............................................74

B.5.6.1 High Voltage Substation And Grid Connection...............................74 B.5.6.2 Ac Power Distribution .....................................................................74 B.5.6.3 Dc Power Distribution .....................................................................75 B.5.6.4 Emergency Power Generation And Distribution .............................75 B.5.6.5 Lighting, Heat Tracing And Other Services ....................................77

B.5.7 Instrument And Control Systems .........................................................77 B.5.7.1 Integrated Control Systems ............................................................77 B.5.7.2 Local Controls And Instrumentation................................................78

B.5.8 Other Auxiliary Systems ......................................................................78 B.5.8.1 Compressed Air And Nitrogen Supply ............................................78 B.5.8.2 Product Tank Farm And Pipelines ..................................................79


Part B September 29, 2006 Page iii

B.5.8.3 Other Storage Tanks ......................................................................83 B.5.8.4 Fire Protection ................................................................................85 B.5.8.5 Flare Systems.................................................................................86

B.5.8.5.1 Low Pressure Hydrocarbon Flare .................................................86 B.5.8.5.2 High Pressure Hydrocarbon Flare.................................................87 B.5.8.5.3 Acid Gas Flare ..............................................................................87

B.5.8.6 Equipment Protection .....................................................................88 B.5.9 Utilities Major Equipment List ..............................................................89

B.6 Alternative Analysis .........................................................................................90 B.6.1 Gasification Vs. Delayed Coking .........................................................92 B.6.2 Gasification Vs. Steam Methane Reforming........................................93 B.6.3 Hydrogen Sales Vs. Cogeneration ......................................................93

B.7 Air Emission Management ..............................................................................95 B.7.1 Sulphur Dioxide ...................................................................................95 B.7.2 Nitrogen Oxides ...................................................................................95 B.7.3 Volatile Organic Compounds ...............................................................96 B.7.4 Particulate Matter.................................................................................97 B.7.5 Odours .................................................................................................97 B.7.6 Visible Emissions.................................................................................97 B.7.7 Air Quality Monitoring ..........................................................................98

B.8 Greenhouse Gas Emissions And Climate Change .........................................98 B.8.1 Introduction ..........................................................................................98 B.8.2 Greenhouse Gas Management Strategy .............................................98

B.8.2.1 Project Ghg Emissions .................................................................100 B.8.3 Climate Change .................................................................................103

B.8.3.1 Effects On The Project..................................................................105 B.9 Waste And Chemical Management...............................................................107

B.9.1 Waste Management Overview...........................................................107 B.9.2 Waste Streams ..................................................................................108 B.9.3 Waste Minimization............................................................................110

B.9.3.1 Pollution Prevention......................................................................111 B.9.3.2 Recycling Program .......................................................................111

B.9.4 Waste Storage And Disposal.............................................................112 B.9.4.1 Waste Streams .............................................................................112 B.9.4.2 Hazardous Waste Storage............................................................112

B.9.5 Chemical Management......................................................................113 B.10 Health, Safety And Environmental Management System And

Contingency Plans ........................................................................................118 B.10.1 Overview............................................................................................118 B.10.2 Hse Leadership And Accountability ...................................................118 B.10.3 Health, Safety And Environment Management System.....................119


Part B September 29, 2006 Page iv

B.10.4 Hse And Related Corporate Policies .................................................119 B.10.5 Planning.............................................................................................122

B.10.5.1 Corporate Hse Goals And Objectives...........................................122 B.10.5.2 Regulatory Requirements .............................................................123 B.10.5.3 Industry Practices And Corporate Expectations ...........................123

B.10.6 Implementation And Operations ........................................................123 B.10.6.1 Occupational Health And Safety...................................................124 B.10.6.2 Environmental Protection..............................................................125 B.10.6.3 Emergency Preparedness And Response....................................125 B.10.6.4 Asset Integrity Management .........................................................127 B.10.6.5 Stakeholder Involvement ..............................................................128 B.10.6.6 Worker Competence And Training ...............................................129 B.10.6.7 Contractor Management ...............................................................129

B.10.7 Monitoring And Review......................................................................130 B.10.7.1 Hse Meetings And Communications.............................................131 B.10.7.2 Incident Reporting And Follow-Up ................................................131 B.10.7.3 Compliance Audits And Inspections .............................................132 B.10.7.4 Performance Measuring, Monitoring And Reporting.....................132 B.10.7.5 Records Management ..................................................................133 B.10.7.6 Review And Improvement.............................................................133

B.10.8 Implementation Of Hse Management System ...................................134 B.11 Approach And Application Of Adaptive Management ...................................134


Part B September 29, 2006 Page v

List of Tables Page

Table B.3.2-1: Typical Asphaltene Characteristics .......................................................... 9 Table B.3.8-1: SCO Characteristics ............................................................................... 19 Table B.3.8-2: Upgrading By-Products .......................................................................... 20 Table B.4.5.2-1: List of Buildings and Sizes................................................................... 38 Table B.4.5.3-1: List of Utilities Buildings and Sizes ...................................................... 39 Table B.4.5.4-1: List of Process Unit Buildings and Sizes ............................................. 40 Table B.5.2.1.2-1: Comparison of Project Water Sources ............................................. 48 Table B.5.2.6-1: Pond Inventory .................................................................................... 60 Table B.5.2.7-1: Overall Water Balance......................................................................... 61 Table B.5.4.1-1: Natural Gas Requirements .................................................................. 68 Table B.5.4.2-1: Project Natural Gas Characteristics .................................................... 69 Table B.5.5-1: Project Steam Demand- High Pressure Steam...................................... 71 Table B.5.5-2: Project Electric Power Demand.............................................................. 72 Table B.5.8.2-1: Process Storage Tank Summary......................................................... 80 Table B.5.8.2-1: Process Storage Tank Summary (Continued)..................................... 81 Table B.5.8.3-1: Storage Tanks ..................................................................................... 83 Table B.5.8.5.3-1: Flare Summary ................................................................................. 88 Table B.5.8.6-1: Utility Housing Summary ..................................................................... 88 Table B.5.9-1: Utilities Major Equipment........................................................................ 90 Table B.6.3-1 Comparison of Key Air Quality Parameters – Power Generation vs.

Maximum Hydrogen Generation.............................................................. 94 Table B.8.2.1-1: Expected GHG Emissions for Construction Phase ........................... 100 Table B.8.2.1-2: Expected GHG Emissions for Operations Phase .............................. 101 Table B.8.2.1-3: Expected GHG Emissions for Decommissioning Phase ................... 101 Table B.8.2.1-4: Expected Total Greenhouse Gas Emissions..................................... 102 Table B.8.2.1-5: Project Contribution to Total Provincial and National GHG Emissions102 Table B.8.2.1-6: Comparison of GHG Emissions with Other Upgrader Projects ......... 103 Table B.8.3-1: Climate Change Scenarios for Edmonton 2050s (2040-2069)............. 105 Table B.9.2-1: Waste Management Summary ............................................................. 108 Table B.9.5-1: Chemical Product Consumption ........................................................... 116


Part B September 29, 2006 Page vi

List of Figures Page

Figure B.1-1: Map of Project Area.................................................................................... 2 Figure B.1-2: Aerial Photo of Project Area ....................................................................... 3 Figure B.3.2-1: Primary Upgrading Process Schematic................................................. 10 Figure B.3.2-2: Solvent Deasphalting Process Schematic............................................. 11 Figure B.3.3-1: Hydroprocessing Unit Schematic .......................................................... 13 Figure B.3.5-1: Gasification and Hydrogen Purification Process Schematic ................. 17 Figure B.3.6-1: Sulphur Recovery Complex................................................................... 18 Figure B.3.9-1: Overall Block Flow Diagram.................................................................. 21 Figure B.3.9-2: Process Streams Balance..................................................................... 22 Figure B.3.9-3: Sulphur Balance.................................................................................... 23 Figure B.3.9-4: Energy Balance..................................................................................... 24 Figure B.4.1-1: General Arrangement – Plant Area Site Plan........................................ 25 Figure B.4.2.1-1: Existing Pipelines and Re-Routing Plan............................................. 28 Figure B.4.3.1.1-1: Temporary Facilities – Site Plan...................................................... 30 Figure B.4.3.1.2-1: Transportation Highway 38 and Highway 643 Access Plan............ 32 Figure B.4.3.1.2-2: Highway 38 Intersection Treatment Plan ........................................ 33 Figure B.4.3.1.2-3: Highway 643 Intersection Treatment 4 Lane Alternate Plan ........... 34 Figure B.4.3.2-1: Transportation Rail Yard Plan ............................................................ 35 Figure B.5.1-1: Project Utilities Interfaces...................................................................... 42 Figure B.5.2.1.1-1: Overall Water Supply Block Flow Diagram ..................................... 46 Figure B.5.2.1.1-2: Water Balance (Gross) Block Flow Diagram................................... 47 Figure B.5.2.1.3-1: River Water Intake and Supply Schematic...................................... 50 Figure B.5.2.1.5-1: Raw and Fire Water Supply Schematic........................................... 55 Figure B.5.2.2-1: Recycle Water Supply Schematic ...................................................... 56 Figure B.5.2.4.2-1: Boiler Feedwater Pre-Treatment/Treatment Schematic.................. 59 Figure B.5.3-1: Industrial, Storm and Domestic Wastewater Schematic ....................... 64 Figure B.5.4.2-1: Natural Gas Supply Schematic .......................................................... 70 Figure B.5.5-1: Steam Distribution Schematic ............................................................... 73 Figure B.5.6.1-1: Power Distribution Schematic ............................................................ 76 Figure B.5.8.2-1: Product Tank Farm Schematic........................................................... 82 Figure B.9.4.2-1: Buildings – Waste Management Facility Hazardous Materials and

Special Waste Building Plan, Section, Elevation ............................. 115 Figure B.10.3-1: Synenco HSE Management System Elements ................................. 120 Figure B.10.3-2: HSE Management Plan Summary .................................................... 121


Part B September 29, 2006 Page 1

B PROJECT DESCRIPTION

B.1 Project Overview

The Northern Lights Upgrader Project (the Project) will upgrade bitumen from Alberta’s oil sands into a higher quality, more valuable, synthetic crude oil (SCO) for market. The Project is a complementary project to the Northern Lights Mining and Extraction Project located northeast of Fort McMurray (for which a separate regulatory application was submitted on June 29, 2006). The Project will receive diluted bitumen from the Mining and Extraction Project and produce nominally 15,900 cubic metres per calendar day (m3/d) (100,000 barrels per day (bpd)) of high quality SCO.

The Project will be located in Sturgeon County, approximately nine kilometres (km) southeast of the Town of Redwater and about 45 km northeast of the City of Edmonton, Alberta. The legal land description is Township 56, Range 21, West of the 4th Meridian. The Project is bounded by Highway 38 on the north, Highway 643 on the west and the North Saskatchewan River (the NSR) on the south, as shown in Figure B.1-1. An aerial photo of the area is presented in Figure B.1-2.

The Project will comprise primary and secondary upgrading of low value, high molecular weight bitumen into higher value, lower molecular weight SCO. By-products that will be produced by the Project are butane, hydrogen, nitrogen, gasifier slag, elemental sulphur and carbon dioxide. A more detailed description of the Project’s upgrading process, infrastructure, utilities and offsites is presented in the following sections.

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B.1.1 Upgrader

The Project will employ a Primary Upgrading stage to separate the fraction found in the bitumen which is not desired for the SCO product, and a secondary upgrading stage to process the desirable oil fractions into a SCO product.

In the Primary Upgrading stage, a Diluent Recovery Unit (DRU), a Vacuum Distillation Unit (VDU) and a Solvent Deasphalting Unit (SDA) Unit will perform the physical separation of the various fractions of the bitumen. The diluent added to the bitumen during the extraction process to make it less viscous for pipeline transmission will be removed by distillation in the DRU and recycled to the extraction plant (which is part of the Northern Lights Mining and Extraction Project described in a separate Application dated June 29, 2006). The gas oils, removed from the bitumen in the DRU and VDU, and Deasphalted Oil (DAO) from the SDA Unit will be sent to the Hydroprocessing Unit (HU) for further processing. The heavier hydrocarbon compounds (vacuum bottoms) from the VDU will be sent to the SDA Unit for the removal of the asphaltene fraction.

The secondary upgrading stage will be a fixed-bed HU that combines demetalization, hydrotreating and hydrocracking of the deasphalted bitumen. Catalytic processes will be used to remove the heavy metals, sulphur and nitrogen from the deasphalted bitumen. Heavier weight hydrocarbon compounds will be converted to lower molecular weight hydrocarbons in the hydrocracking section.

The Project will include a gasification unit to produce synthetic gas (syngas) from asphaltenes, from which hydrogen will be extracted for use in the HU. This will eliminate the need for natural gas as a source of hydrogen and may reduce the Project’s import of power.

B.1.2 Infrastructure, Utilities and Offsites

The Project will be connected to external utilities and related infrastructure existing at the site boundary or offsite within Sturgeon County. These connections include natural gas supply, potable water supply, North Saskatchewan River water supply, sanitary wastewater discharge, and product pipeline, high voltage electric power line, and telecommunications interfaces. Transportation system interfaces include the site access from Highways 38 and 643 and extension of a local railroad system onto the site. Product pipelines will transport diluted bitumen and diluent from/to the Upstream Mining and Extraction Plant, and SCO to market. Other product pipelines will transport gases and liquids to industrial customers.



B.1.3 Site Selection

Alternative locations for the Project were considered by the NLP. Initially, the NLP envisioned an integrated mining, production and bitumen upgrading operation all on the NLP’s Northern Lights Mining and Extraction Project site, north of Fort McMurray. However, due to the significant activity in that area, the NLP considered it appropriate to contemplate other locations for the Project. In terms of connection to existing infrastructure such as power transmission and oil pipelines, and the potential for synergies with other industries (by-product sales, etc.), it was determined that the preferred location for the Project was within the Alberta Industrial Heartland (AIH). Overall, the advantages for locating within the AIH are many and include:

access to market and other infrastructure; synergies with other local industries (availability of feedstock); economics; capacity of local communities to support additional development; labour force availability; and industrial land availability.

During the first seven months of 2005, several potential sites in the AIH, principally in Strathcona and Sturgeon Counties, were investigated for their technical, commercial and economic suitability to become the Project site. High on the list of desired characteristics was a site’s ability to handle the physical needs of the Project. In August 2005, it appeared that land owned, or under option, by Sturgeon County would be the most suitable site. In the period from August through December 2005, Synenco optioned or acquired real property in Sturgeon County. In December 2005, the NLP formally decided to locate the Upgrader on the Sturgeon County site. Since that time, Synenco has continued to pursue the acquisition of various parcels of real property.

B.2 Need for and Purpose of the Project

B.2.1 Need for the Project

Alberta’s oil sands deposits represent one of the world’s greatest concentrations of crude oil and a secure source of energy to meet rising global consumption. These oil sands contain an estimated 175 billion barrels of reserves deemed economically recoverable with today’s technology, placing Canada second only to Saudi Arabia in terms of proven oil reserves.

Industry projections indicate a need for additional oil production to fill the growing gap between global oil demand and the ability of conventional production to satisfy that need.



The situation of rising demand and growing constraints on conventional production has resulted in higher projections for future world oil prices. Over the decades, significant technological improvements have been made in bitumen production and upgrading, resulting in an economic alternative for meeting growing demand for crude oil. The Northern Lights Upgrader Project will provide enhanced upgrading capacity and result in more Alberta oil sands products for world energy markets.

The Project will be developed as an upgrading complex for diluted bitumen transported by pipeline from the Northern Lights Mining and Extraction Project northeast of Fort McMurray. On December 31, 2005, Norwest Corporation, an independent geological consulting firm, issued a report on the bitumen resources contained on the NLP's lands. Based on cumulative drilling data to date and standard reporting requirements, the Norwest report identified best, low and high estimates for the NLP’s bitumen resource base. The best estimate is 1.49 billion barrels of discovered, in-place, bitumen resources, with the low and high estimates being 836 million and 2.38 billion barrels, respectively.

The Upgrader design also provides the option to receive and process third-party bitumen. Bitumen supply from the Northern Lights Mining and Extraction Project is sufficient to supply the bitumen for the Upgrader and support the planned production capacity of 100,000 bpd of high quality SCO from the Upgrader for 30 years.

The Project will add value to Alberta’s bitumen and heavy oil resources by providing the upgrading capacity to produce high quality SCO for downstream refineries to convert into end products. An added benefit of the high quality SCO is greater access to North American refineries.

B.2.2 Benefits of the Project

The Project will result in significant long-term benefits for Albertans and the Alberta economy, including:

a construction workforce of about 2000 (with a peak of almost 3000), which will result in 12,260 direct person years of work;

up to 300 full-time staff personnel for Upgrader operation plus 100 full time contractor roles;

direct government revenues through corporate income taxes and property taxes, of about $4.3 billion dollars (2005 Canadian dollars) accruing to all levels of government over the life of the Project;

more upgrading capacity, which may assist in reducing current heavy oil price differentials, encouraging the further development of Alberta’s bitumen and



heavy oil resources, and which will also help North American refiners by providing useful feedstock for their operations; and

synergies with other industrial facilities in managing environmental and resource issues, including energy, water, air and materials, to achieve mutual enhanced environmental and economic performance.

B.2.3 Economic Viability

A variety of factors affect the economic viability of the Project, including capital cost, operating cost,taxes, technical performance, and commodity prices. Through careful and thorough economic analysis, the NLP believes the Project is economically viable. Thus, the NLP has invested significantly in the Upgrader’s design engineering, land acquisition, environmental impact assessment, and regulatory application. Project economics are based on West Texas Intermediate crude price of US$40 per barrel, future tax expectations and risk allowances that reflect current conditions.

Capital costs for the Project were last estimated to be $3.6 billion (2005 Canadian dollars).

Synthetic crude supply from Western Canada has the potential to more than double in the next five to ten years. However, the quality of current SCO supply may limit its market penetration as most refineries have limited processing capabilities to run significant quantities of SCO. The Upgrader design will allow the NLP to produce a range of SCOs (from approximately 45 API to 49 API) with a sulphur content of less than 0.002%, compared to most other SCOs which have a 34 API and a higher sulphur content. These favourable quality characteristics should enable more refineries to process SCO produced by the Upgrader, which is expected to result in a premium market price. The Project is able to achieve this higher quality product due to the hydroprocessing technology used and the availability of hydrogen from the gasification process.

Bitumen needs to be diluted to be transported by pipeline. The traditional diluent has been condensate, a by-product of natural gas production. With increasing production of bitumen, the demand for diluent is outpacing the supply of condensate. This results in a premium market price for condensate and a demand for diluent alternatives. The Upgrader’s high quality SCO provides a diluent alternative for bitumen producers. The quality of SCO that the NLP chooses to produce will likely vary, depending on the market price for diluent and SCO at the time.



B.2.4 Schedule and Timing

For the purposes of the Application, the Project is treated as a single 15,900 m3/d facility but the Project may be constructed in two stages with each stage producing 7,950 m3/d (50,000 bpd) of SCO. Construction is scheduled to begin in 2008, to achieve first stage production in 2010. Construction for the second stage is scheduled to commence in 2010, to achieve production in 2012. The staged construction of the Project is intended to levelize labour and material requirements, thus improving the ability to effectively manage the Project’s capital cost and schedule performance. However, it is possible that a decision will be made to construct the Project in a single 15,900 m3/d (100,000 bpd) stage during final engineering design. The Project is expected to be in operation for 30 years.

The schedule is dependent on timely regulatory approvals, sufficient engineering definition to reduce uncertainty, construction labour availability and equipment delivery schedules, owners’ business considerations, and owners’ approval to proceed.

B.3 Upgrading

B.3.1 Overview

The Project will use carbon rejection and hydrogen addition upgrading processes to produce a high quality SCO. The major process components of the Project are:

primary upgrading including diluent recovery, vacuum distillation and solvent deasphalting;

secondary upgrading using hydroprocessing; gasification and hydrogen production; sulphur recovery; and supporting utility systems.

B.3.2 Primary Upgrading

The purpose of primary upgrading is to separate out those fractions in the diluted bitumen feedstock which cannot be processed in the secondary upgrader. Diluted bitumen will be received by pipeline and fed to the distillation section, which will consist of a:

Diluent Recovery Unit; Vacuum Distillation Unit; and Solvent Deasphalting Unit.



The first step in the primary upgrading is the DRU, the purpose of which is to recover the diluent used in the extraction process at the mine site. The diluent will be recovered as an overhead stream, collected in product storage and recycled to the extraction plant (which is part of the Northern Lights Mining and Extraction Project described in a separate Application dated June 29, 2006) for reuse. The atmospheric gas oil (AGO) fraction will be recovered from the DRU and sent to the HU. The DRU bottoms stream will be fed to the VDU for further fractionation.

The VDU will recover vacuum gas oil (VGO) for further processing in the HU. Sour gases from the DRU and VDU overhead streams will be sent to a gas treating section for removal of hydrogen sulphide (H2S) so that the gas can be used as fuel. Any water condensed from the DRU and VDU overhead streams will be collected and sent to the Sour Water Stripper (SWS) for the removal of H2S. The gas free water is used within the Project. A schematic of the DRU and VDU is presented in Figure B.3.2-1.

The VDU bottoms stream will be sent to the SDA Unit which is also part of the Primary Upgrading section of the Project. The first stage in solvent deasphalting will consist of mixing the vacuum residue from the VDU with a butane/pentane solvent in a specially designed extractor vessel. A mixture of solvent/deasphalted oil will exit the extractor in the overhead stream and a mixture of solvent/asphaltenes will exit in the bottoms stream. The bottoms stream will be sent to the second-stage stripper for the separation of solvent and asphaltenes. The recovered solvent will be recycled to the extractor and the asphaltenes will be sent to the gasification unit for the production of hydrogen. The extractor overhead stream will be separated into solvent, which will be recycled to the extractor, and DAO, which will be sent to the HU.

Typical characteristics of the asphaltene stream are presented in Table B.3.2-1. A schematic of the SDA Unit is presented in Figure B.3.2-2.

Table B.3.2-1: Typical Asphaltene Characteristics

Characteristic Value Gravity (°API) -7 Sulphur (wt%) 8.20

Energy Content (MJ/kg HHV) 38.9

Primary Upgrading Process Schematic

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B.3.3 Secondary Upgrading

Secondary upgrading of the primary upgrading products will take place in a HU, which converts AGO from the DRU, VGO from the VDU and DAO from the SDA Unit into high quality SCO.

Two identical hydroprocessing trains will be constructed. Each train will consist of a demetalization section and a hydrotreating/hydrocracking section. The demetalization and hydrotreating/hydrocracking sections will have high pressure high temperature reactors that contain fixed beds of catalyst. When the catalyst is spent, the units will be shut down and the catalyst replaced with fresh catalyst. The spent catalyst will be sent off site for disposal.

In addition to the removal of nickel and vanadium, the demetalization section also reduces the Conradson Carbon Residue (CCR) of the DAO. The pretreated DAO product is then processed in the hydrotreating/hydrocracking section together with the AGO and VGO. The hydrotreating section removes the sulphur, nitrogen, residual metals and CCR prior to hydrocracking in which the heavy hydrocarbon molecules are cracked to lighter molecules.

Product from the hydrotreating/hydrocracking reaction section will be cooled to separate hydrocarbon liquids and gases (primarily recycle hydrogen).

The hydrocarbon liquids will be further reduced in pressure and sent to a product stripper. The stripper bottoms product will become the primary SCO blending component. The stripper overhead stream will be routed to a Light Ends Recovery Unit for recovery of diluent, natural gas liquids and fuel gas.

Wash water and condensed stripping steam will be sent to the sour water collection system for further processing in the SWS.

The recycle hydrogen stream will be routed to an amine scrubber to remove hydrogen sulphide. The recycle hydrogen will be supplemented with fresh make-up as required for the HU operation. Rich amine containing dissolved H2S will be routed to the amine regeneration unit within the sulphur recovery complex for the recovery of H2S and returned as a lean solution for reuse. The flash gas from the low pressure section will be sent for hydrogen recovery.

A schematic of the HU is presented in Figure B.3.3-1.

HYDROPROCESSING UNIT

SCHEMATIC

INTEGRATED HYDROPROCESSING REACTOR SECTION

AGO FEED

HYDROGEN

HOT HIGH PRESSURE

SEPARATOR

HOT LOW PRESSURE

SEPARATOR

COLD LOW PRESSURE

SEPARATOR

FUEL GAS TO AMINE ABSORBER

LIGHT ENDS

STRIPPER

AMINE SCRUBBER

RECYCLE GAS COMPRESSOR

LEAN AMINE

RICH AMINE

COLD HIGH PRESSURE

SEPARATOR

RECYCLE WASH WATER

SOUR WATER TO SWS

VGO FEED

DAO FEED

SOUR WATER TO SWS

TO SCO PRODUCT BLEND

OFFGAS TO H2 RECOVERY

MAKEUP HYDROGEN FROM GASIFIER

Steam

CHECKEDDRAWN


31 August2006

JHFigure B.3.3-1

06-010

SCALE

N/A


DW

PREPARED BY

LEGENDTITLE



B.3.4 Air Separation Unit

A two-train cryogenic Air Separation Unit (ASU) will provide the oxygen required for the partial oxidation of the asphaltenes in the gasifier. Nitrogen produced from the ASU will be used as an inert gas for the entire complex, as a diluent in syngas, or for sale as a by-product. The ASU will use electrically driven compression and will require no other energy source. Cooling for the ASU will be provided from the cooling water system (described in Section B.5.2.5)

B.3.5 Asphaltene Gasification and Hydrogen Purification

The asphaltene gasification unit will comprise the gasifier, process water treating, sour high temperature (HT) CO shift, acid gas removal and hydrogen purification. The gasification section will produce all of the hydrogen required for the HU’s with the remainder available for sale. The asphaltene will be sourced from the SDA Unit; however, the gasifier is also capable of handling additional asphaltenes from third parties.

The asphaltenes will be fed to the gasifier with oxygen from the ASU for the partial oxidation of the asphaltenes into raw syngas(comprising CO, H2, CO2, H2S, COS). The raw syngas from the gasifier will be directed to the sour HT CO shift converter for the hydrolysis of COS to H2S and water and the conversion of CO and H2O to H2 and CO2. The shifted gas will feed the acid gas removal unit, where H2S and CO2 will be removed. The H2S and some of the CO2 will be sent to the Sulphur Recovery Complex, and the majority of the CO2 will be cleaned up so as to be suitable for off-site use (e.g., fertilizer or enhanced oil recovery) or venting. The hydrogen stream from the CO2 removal section will be directed to the Pressure Swing Adsorption (PSA) unit for the purification of the hydrogen stream (removal of CO, CO2, and CH4). The 99.9% pure hydrogen will then be sent to compression for the HU. The offgas from the PSA unit, containing light hydrocarbons plus some residual hydrogen will be used as fuel gas within the Project.

A fluxing agent will be added to the gasifier to ensure the production of an inert vitreous slag instead of a fine soot waste stream. The slag will flow from the bottom of the gasifier to a water quench section where it will be cooled and solidified. The slag will exit the quench chamber with some of the quench water. The slag and quench water will be separated, and most of the water will be recycled to the gasification process. Some quench water will be removed constantly from the gasifier water pretreatment circuit and sent as grey water to the IWT Plant for treatment and reuse (see Section B.5.3.2).

Slag from the gasifier is expected to have vitreous characteristics, as the high temperature of the process will be above the melting temperature of most of the minerals in the slag (fluxant and asphaltenes). Unmelted nickel and vanadium from the



asphaltenes will be encapsulated in the glass. Slag from comparable operating gasifier in the United States has consistently been determined to be non-hazardous under U.S. regulations (U.S. DOE 2000). The NLP will investigate the use of slag as a road building material, options that will add economic value to the Project, or will dispose of the material off site in an approved landfill.

A schematic of the gasification and hydrogen production process is presented in Figure B.3.5-1.

B.3.6 Sulphur Recovery Complex

The Sulphur Recovery Complex will include processes for SWS, amine regeneration and sulphur recovery.

Primary and secondary SWS units will process water streams containing H2S, organic sulphur compounds, ammonia and other contaminants. The primary SWS will treat sour water from the various Upgrader process units exclusive of the HU. Sour water from the HU will be collected and processed in a dedicated Secondary SWS to provide recycle wash water of adequate quality for the HU. Operation of the primary and secondary SWS units will be similar and the following description applies to both.

Sour water streams will be collected and combined into a flash drum that will also skim liquid hydrocarbons that will be routed to a recovered oil system. Sour water from the flash drum will flow to a feed surge tank and then to the SWS column. H2S and NH3 will be removed from the sour water using a stripper with a steam-heated reboiler. The reboiler will provide the necessary heat to generate vapour up the column to strip the H2S and NH3 from the sour water flowing down the column. Overhead vapours from the Primary and Secondary SWS will be combined and routed to the Sulphur Recovery Unit (SRU) as feed. A portion of the Secondary SWS stripped water will be recycled to the HU as wash water. The stripped water from the Primary SWS and the portion not recycled from the Secondary SWS to the HU will be sent to the gasifier water circuit.

Rich amine solution from the fuel gas conditioning plant and the HU will be sent to the amine regeneration system for removal of acid gas components. The Amine Regenerator will be a stripper column with a steam-heated reboiler. Rich amine solutions will be fed to the column; the acid gases will be stripped to the overhead product and routed to the SRU. The stripped lean amine from the bottom of the Amine Regenerator will be filtered and recycled to the amine absorber towers located in the upgrading process units.



The SRU will process acid gas streams from the Acid Gas Recovery unit in the gasifier block, the SWS and the Amine Regenerator. For reliability, the plant will use two parallel sulphur recovery trains and a common tail gas thermal oxidizer. The design capacity of the SRU will be 1,300 tonnes per day (tpd) with a stream day throughput of 1,177 tpd of sulphur.

Each sulphur recovery train will consist of a thermal stage followed by a catalytic reactor stage to convert a minimum of 98.8 percent of the feed sulphur to elemental sulphur. The unrecovered sulphur compounds will be oxidized to SO2 in the Thermal Oxidation Unit (TOU) and discharged to a stack.

Two sulphur recovery trains are planned. Each train will process 50 percent of the acid gas throughput under normal operating conditions. The sulphur in the vapours from the catalyst furnace and the catalyst beds will be condensed and flow through seal legs to the sulphur pits. One sulphur pit for each train is planned. The vapour from the last stage will then be routed to the TOU.

During upset conditions or maintenance events, it may be necessary to operate only one sulphur train. In this reduced throughput scenario, the combustion air will be enriched with high-purity oxygen. This will reduce the inert gas flow through the process resulting in increased capacity of the train.

Sulphur in the pit will be degassed and an ejector will sweep air across the headspace to capture sulphur-containing vapours. The sweep air stream will be routed to the TOU. Liquid sulphur in the pits will be transferred to heated storage tanks, prior to shipment for sale via railcars or trucks. Acid gas produced during emergency or upset conditions will be directed to an acid gas flare (see Section B.5.8.5).

A schematic of the Sulphur Recovery Complex is presented in Figure B.3.6-1.

AIR SEPARATION UNIT

GASIFIERS

QUENCH SECTION

GASIFICATION SECTION

ASPHALTENE

OXYGEN

WATER HANDLING

SYNGAS

QUENCH WATER

LOCKHOPPER

SLAG

SLAG SUMP TANK & DRAG CONVEYOR

SLAG FOR DISPOSAL

SOUR SHIFT UNIT

ACID GAS REMOVAL

HYDROGEN PURIFICATION

(PSA)

HYDROGEN TO UPGRADER

OFF GAS TOUPGRADER

ACID GAS TOUPGRADER SRU

AIR

Gasification and Hydrogen Purification

Process Schematic

BLACK WATER HANDLING&

RECYCLE

NITROGEN

CAPTURED CO2

EXCESS HYDROGEN FOR SALE

BLOWDOWN WATER PRETREATMENT

PRETREATED WATER TOUPGRADER WWT

Condensate Return

Makeup Water

BFW STEAMHCU

Off Gas

Fluxant

SCRUBBER

CHECKEDDRAWN


31 August2006

JHFigure B.3.5-1

06-010

SCALE

N/A


DW

PREPARED BY

LEGENDTITLE

Sulphur Recovery Complex

RICH AMINE FROM FUEL GAS SYSTEM

AMINE REGEN

SWS#1

SOUR WATER FROM UPGRADER

STRIPPED SOUR WATER TO GASIFIER

OR TREATMENT

SOUR WATER ACID GAS

RICH AMINE FROM HYDROPROCESSING UNIT

LEAN AMINE TO UNITS

SWS#2

SOUR WATER FROM HYDROPROCESSING UNIT

STRIPPED SOUR WATER TO HYDROPROCESSING

UNIT OR GASIFIER OR TREATMENT

AMINE ACID GAS

SOUR WATER ACID GAS

ACID GAS FROM GASIFIER

THERMAL OXIDIZER UNIT

SULPHUR DEGASSING

ACID GAS FEED

ACID GAS FEED

ACID GAS

TO STACK

TRUCK OR RAIL CAR LOADING

SULPHUR STORAGE

CHECKEDDRAWN


31 August2006

JHFigure B.3.6-1

06-010

SCALE

N/A


DW

PREPARED BY

LEGENDTITLE

SULPHUR DEGASSING

SULPHUR STORAGE

Sulphur Recovery Unit #2Incremental Conversion

Unit

Sulphur Recovery Unit #1Incremental Conversion

Unit



B.3.7 Supporting Utility Systems

The Project will require a number of supporting utility systems, including:

natural gas supply; electric power supply; raw and potable water supply; water treatment; wastewater treatment and reuse or disposal; cooling water supply; compressed (plant/service and instrument quality) air; stormwater collection and reuse or release; fire protection; flare; product tankage and pipelines; process buildings; and operation and maintenance buildings.

A detailed description of the supporting utility systems is provided in Section B.4 and Section B.5.

B.3.8 Upgrader Product

The primary purpose of the Project is to produce a high quality SCO, with properties as shown in Table B.3.8-1. In addition to this primary product, the Project will produce several materials for use internally in the upgrading process, including make-up bitumen diluent, make-up asphaltene solvent, hydrogen, electric power, steam, water for reuse, and fuel gas. In addition to the primary product of SCO, some by-products also will be produced and marketed to outside parties (Table B.3.8-2). Although the Project will have the ability to produce a SCO ranging from 45 API to 49 API, the engineering and technical information presented in this Application are based on a 49 API case.

Table B.3.8-1: SCO Characteristics

Parameter Value Product sulphur (ppm by weight) 20 Product density (°API) 49 Product yield (volume % on bitumen feed) 89.5%



Table B.3.8-2: Upgrading By-Products

By-Product Quantity Butane 859 m3/sd Hydrogen 5,580,000 m3/sd Liquid Sulphur 1,177 t/sd Slag (wet – 50% water)1 500 t/sd Carbon Dioxide 13,344 t/sd Nitrogen 16,995 t/sd

1: Maximum Design Slag 2: Make-up diluent of approximately 80 m3 /sd returned to Northern Lights Mining and Extraction Project

B.3.9 Material and Energy Balances

An overall block flow diagram of the upgrading process is presented in Figure B.3.9-1. A process stream balance is shown in Figure B.3.9-2. A sulphur balance is provided in Figure B.3.9-3. An energy balance is presented in Figure B.3.9-4.

B.4 Infrastructure

B.4.1 Overview

The layout and location of the proposed facilities are shown on Figures B.4.1-1. The Project site will include the upgrading process area, the utilities area, the tank farm, water ponds and the administration support area.

The site is bounded on the north by Highway 38 and on the west by Highway 643. Access to both of these highways is proposed. Sturgeon County is currently conducting a Transportation Master Plan (TMP) that will address road, rail, and pipeline access for the Heartland Industrial Area. The TMP will define potential changes to the roadway system in the area.

DiluentRecovery

Unit(DRU)

Sulphur 1,072 t/d

Deasphalted Oil (DAO)

Vacuum Gas Oil (VGO)

Atmospheric Gas Oil (AGO)Light End Recovery

Nitrogen

Diluent Return 7,778 m3/d (48,921 bpd)

Diluted Bitumen Feed

Diluent

VDU Feed

Oxygen

Slag

Sour Water

Sour Water

Sour Gas

LEGEND

CHECKEDDRAWN

FIGUREPROJECTDRAFT DATE18 September 2006

JHFigure B.3.9-1

TITLE

OVERALL BLOCK FLOW DIAGRAM 06-010

Gas Stream

Water Stream

VacuumDistillation

Unit(VDU)

Vacuum Bottoms

Solvent Deasphalting

Unit(SDA)

Hydroprocessing

Asphaltenes

Sour Water

Gasifiers

AirSeparation

Fuel Gas For Process Use

Butane773 m3/d(4,864 bpd)

Synthetic Crude Oil16,087 m3/dSulphur 0.25 t/d(101,187 bpd){Note 1}

Sour WaterStripping

AmineRegeneration

Acid Gas

Hydrogen

Hydrogen toHydroprocessing

CO2

Hydrogen to Sales

Acid Gas

Sulphur Recovery Unit

(SRU)

Sulphur 1,071.75 t/d

Sulphur1,058.9 t/d

SO2 to Atmosphere12.85 t/d of SulphurEquivalent

PREPARED BY

To ExtractionFacility

SCALE

N/A

17,982m3/d Bitumen (113,105 bpd) 7,706 m3/d Diluent ( 48,471 pbd)

25,688 m3/d Diluted Bitumen (161,576 bpd)

Fluxant

Acid Gas Removal CO2

(H2S & CO2)

Hydrogen Purification

Purge gas to Fuel

HydrocarbonLiquid Stream

Air

Acid Gas

Note 1:The nominal capacity of the facility is 15,900 m3/d (100,000 bpcd) butthe estimated production could reach 16,087 m3/d (101,187 bpcd) forthe same bitumen feed.

Note 2:All flowrates are in calendar days


DW

SCALE 1:15000m

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PL BHCHECKED Figure B.4.1-1

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B.4.2 Site Preparation

The objective of site preparation will be a well-graded, self-draining site that will allow all-weather access for construction and ultimately operation and maintenance. Regional surface drainage will be directed around the planned development. Diversions will be constructed so that drainage will occur into the existing drainage courses away from the site, to waterbodies including the Redwater River and the NSR. Topsoil will be stripped and stockpiled for future use in reclamation activities. The NLP’s approach to topsoil handling and management is described in the conservation and reclamation plan, presented in Volume 2, Section E.5 Soils and Terrain and in Volume 3, CR #5 Soils and Terrain. Some of the topsoil will be stored in berms around the site on the north and west sides and some will be stored as shown on Figure B.4.1-1. The berms will also serve to attenuate noise and visual intrusion onto surrounding properties and be used as a landscape element to enhance the visual blending of the plant area into the surrounding environment.

Site grading will begin after the topsoil has been removed and stockpiled and the initial drainage ditches constructed. The stripped areas are to be graded at 2% towards the nearest construction-phase drainage ditch. Drainage ditches will be constructed for a design velocity of 0.9 metres per second (m/s) or less during a 1 in 25 year precipitation event. During site development, entry of overland flows from the surrounding catchment areas will be restricted by the existing roads around Sections 32 and 33. These flows will be collected in existing side ditches that run along the exterior roads.

Rainfall on the Project site during construction will be collected using a system of ditches that will carry the water by gravity to a sediment pond where it will be clarified by settling time prior to being discharged to the NSR. The sediment pond will be designed to allow the water collected in a 1 in 100 year storm event to be stored and released over a 24-hour period. Erosion protection will be installed at the pond outfall, and may include gabion baskets, geotextiles, culverts and stilling basins. The location of the sediment pond is shown on Figure B.4.1-1.

An erosion and sediment control plan will also be implemented during construction for all work areas, including the construction lay down areas. A spill control and countermeasures program will be implemented during construction and operation to ensure that hydrocarbons are properly managed and kept out of all water sources, storage ponds, and waterway flows, and that spills are detected early and addressed properly.

The recommended structural fill for the Project site is based on a 150 mm sub-grade and a California Bearing Ratio of >3 percent. On top of the subgrade, an additional 150 mm of 20 mm minus granular material will be placed and compacted to 98% Standard



Proctor Dry Density. Road grades are designed with additional crush and pit run gravel over the prepared subgrade. Internal roads will be designed for future asphalt paving.

A temporary lay down and storage area will be established in the northeast quarter of Section 32, adjacent to the temporary construction management and contractors’ offices. The lay down area will be approximately 158,000 m2 in area and will have a gravel surface. Temporary structures with concrete floors will be installed to protect certain components from the elements.

B.4.2.1 Demolition

There are existing facilities such as abandoned and operating oil wells, associated underground piping, and abandoned buildings on the property that will be removed as required prior to developing the site. In addition there is a 138 kVA powerline and an oil transmission pipeline that are to be relocated as part of the site development. The locations of the existing pipeline and transmission line are shown on Figure B.4.2.1-1. The powerline will be re-routed through the easement around the NLP property to the west and along the west border.

B.4.2.2 Concrete Batch Plant

Concrete will be one of the construction materials used during construction of the Upgrader. The location of the batch plant will be near the Project site to minimize the travel distances for transporting concrete. The equipment, silos and buildings will be provided by a concrete batch plant contractor. The contractor will be responsible for the transportation of cement, water, and aggregate. These materials will be trucked to the site on a demand basis as required by the contractor. Water supply will be arranged by the concrete batch plant contractor.

0SCALE 1:1000m

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CHECKED B.4.2.1-1

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InfrastructureExisting Pipelines & Rerouting Plan UMA Engineering Ltd.

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B.4.3 Transportation

B.4.3.1 Roads

B.4.3.1.1 Construction Access

Temporary parking and bus marshalling facilities will be constructed on the northeast quarter of Section 32. The site will be near the Highway 38 access, adjacent to the temporary security gate. The area provided for the bus terminal and vehicle parking areas will be constructed with a gravel base. The layout of the temporary parking and bus marshalling areas is shown on Figure B.4.3.1.1-1.

Roads on the site will be required early in construction to provide access to the construction management offices, the contractor offices, temporary security gate and emergency medical facilities, the parking lots for buses and cars, and lay down and storage areas. The main access to the site will be off Highway 38. Gravel surface finished roads will be constructed to and within the site to access the various temporary facilities. Temporary access plans and parking facilities during construction are shown on Figure B.4.3.1.1-1.

B.4.3.1.2 Upgrading of Access Roads and Intersections

The need for and extent of upgrading the roadways and intersections to be used in accessing the Project site has been assessed based on a preliminary traffic impact assessment (TIA) completed for the site. Information regarding the TIA and predicted effects is presented in Volume 4, CR#12 Socio-Economic Impact Assessment and in Volume 4, CR#13 Traffic Impact Assessment.

Two access points are planned for the site, one off Highway 38 and one off Highway 643. The location of the access points is shown on Figure B.4.3.1.2-1. The main access point for construction and operations personnel will be from Highway 38. The proposed configuration of this access point (referred to as the North Access Road) is shown on Figure B.4.3.1.2-2. The secondary access which will be used for delivery vehicles and materials supply is to be located off Highway 643 (referred to as the West Access Road). The layout of this intersection is shown on Figure B.4.3.1.2-3.

SCALE 1:2500m

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Analysis completed for the TIA indicates that the intersection of Highway 38 and 643 will require upgrading with additional turning lanes as a result of increased traffic from the project and other developments in the area. The proposed new intersection layout is shown on Figure B.4.3.1.2-1. Turning lanes will also be required on Highway 38 at the North Access Road and on Highway 643 at the West Access Road. The proposed layouts of these intersections are shown on Figures B.4.3.1.2-2 and B.4.3.1.2-3. Currently the TIA analysis indicates that signals are not required at these intersections, however this could change depending on future development in the area.

The intersections and roadways will be designed to accommodate peak traffic based on the TIA and will meet standards and guidelines of Alberta Infrastructure and Transportation.

B.4.3.2 Rail

The Project site will be serviced by rail in addition to the vehicular traffic discussed in Section B.4.3.1. The rail yard will be used for shipping and receiving bulk commodities such as sulphur, flammable hydrocarbons, and wastes such as the gasifier slag. The rail yard will consist of:

one receiving track for arriving inbound traffic; one departure track for outbound traffic; one thoroughfare for internal switching access to the loading/unloading tracks

and for moving of the locomotives; one or two future receiving/departure tracks for use if future traffic warrants their

addition; and tracks for loading/unloading with three loading/unloading locations.

The location and layout of the rail facility is shown on Figure B.4.3.2-1.

CN’s rail carrier service provides for the pick up or drop off of cars to the receiving or departure tracks. Synenco will be responsible for moving cars from the loading/unloading tracks to and from the receiving/departure tracks with a yard engine or trackmobile.

SCALE 1:8000m

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TransportationHighway 38 and Highway 643 Access

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TransportationHwy 643 Intersection Treatment

4 Lane Alternate PlanB.4.3.1.2-3


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B.4.4 Temporary Infrastructure Tie-ins

Temporary power will be required for construction activities, construction management offices, other temporary activities, and lighting of parking lots and other areas. This power may be obtained from Fortis Alberta, or provided via temporary on-site generation (diesel generators). Pad mount transformers will be installed at four locations throughout the site to distribute the construction-phase power and service the construction offices and the needs of the contractors.

During construction, potable water will be trucked from a nearby water treatment facility or obtained from the Capital Region Northeast Water Services Commission (CRNWSC) pipeline located near the site.

Temporary sewage collection tanks will be installed for the construction management offices and other temporary facilities during construction. Wastewater will be hauled from the collection tanks by truck to the nearest available wastewater treatment plant.

B.4.5 Buildings

B.4.5.1 Temporary Construction Management Buildings

Temporary construction management offices for Project personnel and contractors including engineers, surveyors and supervisors, will consist of trailer/skid-type offices installed near the temporary security gate, Fire Hall/Emergency Medical Services (EMS) building, and temporary lay down area. The management offices will initially accommodate 80 personnel but will allow for expansion to 320 personnel. At completion of the construction, the temporary facilities will be decommissioned and removed from the site.

B.4.5.2 Administration and Maintenance Buildings

The administration and maintenance buildings include the Administration Office Centre, Warehouse/Maintenance Building, Upgrader Operations Centre, Upgrader Maintenance Buildings, other warehouse type buildings, Fire Hall/EMS Building, and Security Gate and Booth. The Administration Office Centre will be occupied by Project site administration personnel, engineering and certain operations personnel, and will comprise a built-in-place, multi-story structure. The various functions of the Administration Office Centre will include:

visitors’ orientation and security area; first aid room; men’s and women’s locker rooms;



conference and training areas; laboratory with direct access to the exterior for sample receiving; mail room; and offices and workstations.

The Warehouse/Maintenance Building will be occupied by warehouse and maintenance personnel including supervisors and maintenance staff, and will include:

two maintenance bays with 25 tonne overhead cranes; shop bays for electrical/instrument repairs, welding, and machine repairs that will

be equipped with jib cranes; interior drive aisle; tool crib, warehouse and storage; warehouse storage with floor to ceiling pallet metal racking that will be accessed

by forklifts; other types of storage areas including floor storage, reel racks, cantilever racks

and a flammable storage area; lockers; offices; and shipping and receiving.

Other smaller and separate buildings will also have operations, maintenance, and storage functions. These are the Upgrader Maintenance Building, the Upgrader Operations Centre, Cold Storage Building, Hazardous Materials and Waste Management Building and the Bundle Wash Building. The Upgrader Operations Centre will house the main control room, electronics/telecommunications room, training room, lunch and lavatory facilities, files, and other facilities. The Bundle Wash Building is where heat exchange bundles will be periodically cleaned when the efficiency is reduced due to fouling.

The Hazardous Materials and Waste Management Building will house paint, painting materials, solvents, oils, and other materials and wastes that are considered flammable, combustible or hazardous. The building will provide suitable containment to prevent spills, will be equipped with automatic fire protection systems, and will be situated away from other Upgrader facilities for security and fire separation.

The functions of the Fire Hall/EMS Building will include:

EMS walk-in clinic;



fire hall designed for three fire trucks and two ambulances; facilities for fire extinguisher and air-pack maintenance; decontamination area with emergency showers and treatment rooms; lockers, laundry and equipment storage; administrative area and lunchroom; and training and fitness area.

The Security Gate and Booth will serve as primary control for access to and from the Project site. The Booth facility will incorporate a guard booth, a mobilized gate for vehicles, a pedestrian gate, offices and a site monitoring system using remote cameras.

The on-site administration, maintenance and warehouse buildings with their respective sizes are listed in Table B.4.5.2.-1.

Table B.4.5.2-1: List of Buildings and Sizes

Building Name/Description Area (m2) Height (m) Administration Office Centre 2,520 7 Upgrader Operations Centre 3,600 7 Fire Hall / EMS Building 2,775 7 Warehouse/Maintenance Building 5,655 15 Upgrader Maintenance Building 864 15 Security Gate and Booth 16 3.6 Bundle Wash Building 225 10 Cold Storage Building 480 7 Hazardous Materials and Waste Management Building 900 7 Weigh Scale Building 16 3.6

B.4.5.3 Utilities Buildings

There are also a number of buildings associated with the utilities of the plant site. These include specialty engineered, pre-engineered, or small pre-manufactured buildings. The final size of many of these buildings has not yet been determined. The most substantive buildings associated with the utilities and the major equipment contained in these buildings are listed on Table B.4.5.3.-1.



Table B.4.5.3-1: List of Utilities Buildings and Sizes

Building Name Description Area (m2) Height (m) Water Treatment Building

Boiler feedwater, air compressors, boiler auxiliaries 8,125 11

Substation Control Building

High voltage electrical equipment (breaker controls, SCADA, protective relays, metering)

54 4

Steam Turbine/Generator Building

Steam turbine/generator and auxiliaries 1,120 14

Electrical Building High and medium voltage switchgear and control centers, station battery, uninterruptible power supply

N/A N/A

Raw/Fire Water Pump Station

Raw water and fire suppression pumps and related equipment 1,140 12

River Water Intake Pump Station

River water intake pumps, traveling screens, and related equipment 96 10

Recycle Pump Station

Recycle water pumps and treatment equipment 1,680 14

IWT Station Industrial wastewater treatment (IWT) equipment 3,000 8

Sanitary Lift Station Sanitary forwarding pumps, basin, and related equipment 9 3

Dilbit, Diluent, SCO Pump Station

Dilbit, diluent and SCO pumps 900 5

Intermediate Product Pump Station

Intermediate product pumps 900 5

Light Ends Pump Station Light ends pumps 900 5 Cooling Tower Chemical Treatment Building

Cooling tower chemical treatment 100 5

Stormwater Pump Station

Stormwater pumps 225 7

Primary WTP Building Flocculation and filtration equipment 4,200 7

B.4.5.4 Process Buildings

The most substantive of the buildings associated with upgrading processes are presented in Table B.4.5.4-1. These buildings are generally pre-engineered construction with insulated metal siding.



Table B.4.5.4-1: List of Process Unit Buildings and Sizes

Unit Building Name - Description Area (m2)

Height (m)

10 – DRU/VDU Power Distribution Centre 150 10 10 – DRU/VDU Power Distribution Centre 150 10 10 – DRU/VDU Low Pressure Compressor Building 144 12 20 - Deasphalting Power Distribution Centre 150 10 30 – Hydrotreater/Hydrocracker

Power Distribution Centre 150 10

30 – Hydrotreater/Hydrocracker

Power Distribution Centre 150 10


Make-up Hydrogen Compressor Building 576 18


Recycle Gas Compressor Building (Train 1) 360 18


Recycle Gas Compressor Building (Train 2) 360 18


Operation Satellite Building #1 140 3.6

40 – Sulphur Unit Power Distribution Centre 150 10 40 – Sulphur Unit Power Distribution Centre 150 10 40 – Sulphur Unit Sour Water Building 2140 15 40 – Sulphur Unit Amine Building 940 15 40 – Sulphur Unit Warm-up Room 27 4.5 40 – Sulphur Unit Sulphur Loading Shelter 78 11 50 – Gasification/H2 Power Distribution Centre 150 10 50 – Gasification/H2 Power Distribution Centre 150 10 50 – Gasification/H2 Gasifier Building 280 15 50 – Gasification/H2 Slag Storage Building 800 15 50 – Gasification/H2 AGR Building 5250 20 50 – Gasification/H2 AGR Compressor Building 2560 18 50 – Gasification/H2 CO2 Compressor Building 1500 18 50 – Gasification/H2 Blowdown Building 600 12 50 – Gasification/H2 Water Treatment Building 260 12 50 – Gasification/H2 Operation Satellite Building #2 140 3.6 60 – ASU Power Distribution Centre 150 10 60 – ASU Power Distribution Centre 150 10 60 – ASU Compressor Building 630 18 60 – ASU Air Separation Unit Building 120 6

B.5 Utilities and Offsites

B.5.1 Overview

A number of utility systems will be required to support SCO production including:

raw and potable water supply;



water treatment and management; wastewater collection, treatment and disposal; developed area stormwater collection, treatment, reuse, and disposal; natural gas supply and distribution; auxiliary steam generation and power generation; electric power supply and distribution; instrumentation and controls, including an integrated control system (ICS) for the

Project; other auxiliary/utility systems including compressed air and nitrogen supply,

product tank farm and pipelines, fire protection, and flare systems; control and utilities equipment environmental protection and enclosure; pipelines for hydrogen, CO2, nitrogen export; and liquid sulphur rail loading.

Brief overviews of each of these utilities are provided below, with more detailed supplemental system definitions, physical and process descriptions and related process flow diagrams or schematics for the Project presented in the following sections.

Figure B.5.1-1 provides a summary of external utilities interfaces for the Project.

Two primary sources of water will be used by the Project, consisting of raw water from the NSR and potable water. The selection process used to arrive at these sources is described in Section B.5.2.1. The raw water will serve two primary functions: (1) dedicated source of water for on-site fire suppression, and (2) make-up to Upgrader cooling and other process water systems. To minimize overall river water consumption, the raw water used in Upgrader systems will be recycled to the maximum possible extent (see Section B.5.2.2). The raw water will also be treated via several treatment systems prior to use in any process, other than in direct use for fire suppression. In addition, stormwater collected from developed areas will be collected, treated as required, and also recycled for use as cooling water and other applications.

It is intended that the permanent potable water supply for the Project will be from the regional CRNWSC line. Discussions with the CRNWSC are currently underway. Potable water from the CRNWSC will be used for drinking water and serve other uses where potable water suitable for human consumption and contact is required (e.g., eyewashes wash stations and plumbing system functions).

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Options for domestic/sanitary wastewater include either sending the sanitary waste stream to a proximate Municipal Wastewater Treatment Plant or on-site treatment. Industrial wastewater generated in Project systems will be collected, treated and returned to the recycle water pond for re-use.

Natural gas will be procured from a third party, reduced in pressure, and used in a number of processes in the Project as a clean fuel source, including auxiliary steam generation, make-up to the Project fuel gas system, and building heating. Natural gas will also be used in the flare stacks as a continuous ignition source and for acid gas enrichment and lift and may be used in product storage tanks as a blanketing medium.

High pressure steam will be generated via auxiliary boilers, in addition to steam internally generated in the gasifier and SRU. The supplied steam from these sources will support the steam demands in various processes within the Project complex, including product and space heating, equipment drives and limited electric power generation in a condensing ST/G. The auxiliary boilers will operate during Upgrader start-up, at part load during normal plant operations, and as required during abnormal operations when other process steam producers are not available.

Electric power required for base Upgrader operations will be partially self-generated via an on-site ST/G with the balance to be procured from the Alberta Power Pool through the Project substation interconnection with the Alberta Interconnected Electrical System (AIES). Power distribution of the incoming AIES circuit(s) to Project users will be accomplished via step-down transformers, circuit breakers, disconnect switches, and conventional bus equipment in an on-site substation and distribution stations.

An integrated control system (ICS) will be employed to allow Project operators to safely operate the facility and subsystems from a central point. The ICS will use current-day distributed controls technology to interface with localized subsystem controls, and will contain features such as sequence-of-events, data acquisition, and safety integration systems to facilitate trending and timely operator response to abnormal conditions. Primary ICS human machine interface (HMI) will be in the Control Room, situated in the Upgrader Operations Centre.

Other auxiliary utilities involved in supporting Upgrader operations include central compressed air and back-up nitrogen supply systems; a product tank farm and pipeline system to support incoming diluted bitumen, outgoing diluent, intermediate products, and produced SCO; fire protection (detection and suppression) system, and three vent header systems with flare stacks for safe disposal of gaseous products during process or equipment upset conditions.



Enclosures and utilities-related buildings associated specifically with the Utilities component of the Project include the Water Treatment Building, 138 kV Substation Control Building, Steam Turbine/Generator Building, and miscellaneous enclosures housing pumps, local water and wastewater treatment equipment and lift stations, and electrical/controls and fire suppression equipment.

B.5.2 Water and Water Treatment

This section outlines the water requirements (demands) of and sources for the Project, and describes the various water systems that will be used in Upgrader operations and processes.

B.5.2.1 Water Demand and Supply

B.5.2.1.1 Demand

Raw water will be required as a means of providing cooling water to Upgrader equipment, to support on-site fire suppression, and as a source for producing both boiler feedwater and service water. In order to assess potential raw water sources, the total demand from these users was estimated for several anticipated operating conditions. The demand for potable water required to support drinking water, plumbing, and safety systems at the Project was also separately estimated. In summary, the Project will use raw water to meet the following needs:

make-up water for cooling tower evaporative losses and blowdown (continuous); boiler feedwater make-up for steam losses and blowdown (continuous); process water make-up (continuous); service water purposes throughout the Project, including wash water (periodic);

and fire suppression water (periodic).

The overall water flow block diagram is shown in Figure B.5.2.1.1-1, with description of specific demands contained in Sections B.5.2.4 to B.5.2.5. Raw water demands on an annual, hourly and peak instantaneous basis are outlined in Section B.5.2.7. Peak NSR water withdrawal for pond and system filling during startup and infrequent short-term events such as make-up to the raw/fire water pond during a potential fire occurrence is 1.2 m3/s. Figure B.5.2.1.1-2 depicts schematically the acquisition of raw water from the NSR and the recycling of various streams

In addition to process demands, the Project will also lose water in the form of evaporation from ponds and open systems. Because the Project will collect and recycle



water used in various processes for make-up to cooling systems and the gasifier, and such uses have limits on contaminant levels entrained in the water, certain wastewater streams must either be treated or disposed. Streams including backwash from the RO and blowdown from mixed bed ion exchange (MBIX) equipment (boiler feedwater treatment) are especially high in total dissolved solids (TDS) and are candidates for disposal. This process is further described in Section B.5.2.2.

Demand for potable water was based on the predicted size of the work force on the Project site at various phases, with peak work force to be served later during construction and into start-up/commissioning, when permanent plumbing systems will be available.

B.5.2.1.2 Supply Sources

In its examination of alternative sources of water supply, the NLP considered reliability of supply, efficiency, environmental implications and technical feasibility, with a priority placed on recycling and reuse. In addition, the NLP explored the use of existing potable and non-potable water and wastewater systems in the region as a means of minimizing environmental effects. Table B.5.2.1.2-1 is a summary of the water supply options considered for this project.

RAW WATER POTABLE WATER

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Table B.5.2.1.2-1: Comparison of Project Water Sources

Source Comments North Saskatchewan River Readily available at the southern boundary of the Project site,

with sufficient quantity and quality to support all Project needs, including fire suppression, normal make-up and potable streams.

On-Site Well Water Initial geotechnical testing found few to no shallow aquifers or perched water.

Research for region found few deep aquifers of suitable, reliable capacity.

Surface Waterbodies within Project Site

Review of the Project site identified only a few seasonal ponds and a small creek at the south boundary, with insufficient water available for use.

Stormwater Stormwater from undeveloped areas of the site will be allowed to discharge via current paths, with that part of the flow naturally draining to the NSR through a sediment pond and then through natural channels to the River.

Infrequency of storm flow and quantity limits use for meeting all Project make-up water demands, but stormwater from developed areas will be recycled and used to reduce surface water withdrawals by the Project.

Capital Region Northeast Water Services Commission (CRNWSC) – Industrial Heartland

Water source (potable quality) available to Project at published cost.

Source of this water is also the NSR, with additional treatment by CRNWSC to meet Alberta standards for drinking water.

Insufficient volumes available in current system to handle all Project water demands.

Recycle Water This is the capture of previously used water within the Project for reuse.

Suitable reliability (as water exists on-site) although insufficient in total to meet all Project demands.

Recycle water will be treated to allow reuse, certain wastewater streams generated in the IWT plant will require deep well disposal.

Will be used as much as possible to defer the amount of water withdrawn from the NSR.



B.5.2.1.3 Demand/Supply Summary

Based on the assessment of the Project water demand and available water supply sources, the NSR will be the primary source for the raw water for the Project. However, it is the goal of the Project to minimize all water consumption from natural sources and to recycle as much water as economically possible. The demand for the NSR water will vary depending on many factors including plant operating status, climatic conditions affecting evaporation and cooling, and stormwater capture and reuse. Annual average demand for the maximum water cooling case is reported in Section B.5.2.7. This demand is primarily driven by make-up needs for plant cooling and air separation equipment and hydrogen production.

Figure B.5.2.1.3-1 is a Block Flow Diagram showing the river water supply schematic. The exact location of the NSR water intake will be determined during detailed engineering and will be addressed in a separate regulatory application.

As opposed to other water supply alternatives such as “manufacturing” potable water from a raw water source, the preferred option is to obtain potable water for the Project from the CRNWSC. Prior to substantive on-site construction, the NLP will apply for and make connection to the existing CRNWSC-owned potable water supply line along the west boundary of the Project. Water from this 30 cm diameter line will support the remaining construction phases, and will be left in place for permanent potable supply to the Project. Additional discussion is contained in Section B.5.2.3.

B.5.2.1.4 Raw Water (River) Intake and Pipeline System Description

A river water intake pump station will be built on the north bank of the NSR above the 100 year flood level inclusive of an allowance for ice. As the river is shallow near the bank, a submerged intake will be used instead of the more traditional bank style intake. The submerged intake and fish screens will be constructed in accordance with DFO guidelines and is expected to be in deeper water well out in the channel and connected to the pump station by buried pipes. The exact location of the submerged intake and the choice of intake type will be reviewed during the detailed engineering phase of the Project based on river engineering studies and geotechnical investigations.

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Once bathymetric surveys are available, the location of the submerged intake will be chosen and discussed with the Navigable Waters Protection branch of Transport Canada (NWP). Deeper pockets in the river near the plant site will be sought using the bathymetric surveys in order to provide the greatest possible clearance over the submerged intake for recreational boating traffic. The design will be based on consultation with NWP and the location of the submerged intake will be marked by buoys and signage upstream and downstream as required by NWP.

The intake structure/pumps and pipeline will be constructed on the north bank of the river, using construction techniques that minimize effects on the river. An access road will be constructed along the pipeline to provide operations and maintenance access to the intake. The intake pipeline will discharge into the raw/fire water pond.

The river water pipeline will be designed in accordance with the requirements of CSA Z662 (and ASME B31.3 Code, Process Piping), with various coating systems and cathodic protection systems to be evaluated during detailed engineering. Water pipelines will likely be buried to prevent freezing and the line sizes will be confirmed during the detailed engineering. The steel river water pipeline will be approximately 760 mm (30 inches) in diameter.

During detailed engineering, there will also be further evaluation of the pipeline design including:

a study to refine the economic pipeline diameter; transient analyses to examine the water hammer pressures and select surge

protection devices; studies to select and locate the air release valves; and layout studies to refine the location in plan and profile and ensure the pipeline

can be drained.

The water intake and associated facilities will be applied for in separate regulatory applications. Those applications will include detailed assessment of the specific design and location of the water intake.

B.5.2.1.5 Raw Water Consumption

Following on-site construction of the intake structure, pumps, pipeline and ponds, the raw/fire water pond will be filled (including dedicated volume for fire suppression and make-up). Make-up flows from the river and raw/fire water pond during the first and second phases of the Project will vary, as a function of raw/fire water pond level control. The potential environmental effects of the Project on surface water are assessed in



Volume 2, Section E.9 Surface Water. Consideration will be given during the detailed engineering phase of the Project to further minimize river intake needs, principally through consideration of alternate cooling technologies. Plans to recycle raw water are described in Section B.5.2.2.

Figure B.5.2.1.5-1 provides an overview of the Project raw water supply and distribution system. The raw/fire water pond will be constructed such that it always maintains sufficient volume for the suppression of postulated fires within the Project facility, while maintaining sufficient volume for periodic supply of make-up water to the recycle water pond (Section B.5.2.2) and continuous supply to the feedwater/service water systems (Section B.5.2.4).

An initial estimate of peak fire water demand was defined as 4,088 m3/h for a duration of six hours; the equivalent volume of water will be stored at the bottom of the pond, with all other users taking suction from volume above this amount. Upon fire pump start and consumption of significant pond water volume, the lead river intake pump(s) will also start to ensure that sufficient extinguishing capability is provided for long-term suppression needs.

B.5.2.2 Water Management and Treatment

Water for process and cooling system use will be supplied principally from the recycle pond; this pond will preferentially receive make-up water from the stormwater pond and the IWT plant, with the balance provided from the raw/fire water pond. Water sources and uses were previously described in Section B.5.2.1. To minimize the amount of raw water required, the Project will maximize recycling of all water which has been used in various Project systems or captured from storm events, via use of an on-site recycle water pond. A series of water treatment practices will be employed on pond influent/effluent streams to ensure that this water is reusable in the various processes and cooling loops. Limited deep-well disposal of streams containing high dissolved solids will also be needed. Opportunities for reducing water use and maximizing water recycle and thus reducing river water intake will continue to be evaluated and implemented as practical throughout the design and operating life of the Project. The recycle water supply schematic is provided in Figure B.5.2.2-1.

Stormwater from developed areas on site, including areas where hydrocarbons may be present, will be collected, routed through an oil/grit separator, and stored for interim periods in the stormwater pond. Normally, this stormwater will be pumped through a fine media filter to remove suspended solids prior to discharge into the recycle water pond. The stormwater pond will be outfitted with equipment to remove any oil which has entered the pond and, in the event that significant oil contamination is present, pond volume will be processed through an API oil/water separator and industrial treatment



before disposition into the recycle pond. All processed stormwater, and other wastewater discharged from industrial wastewater treatment will first deposit in a polishing pond for verification of quality before passage to the recycle pond. Through this process, maximum recycling of water can be accomplished while recycle pond water quality is maintained within limits required by downstream users. When recycle pond low level is signaled, make-up from the raw/fire water pond will enter after having passed through flocculation and settling of solids.

During periods when the recycle water pond level is high, water from the recycle water pond will be diverted to the primary treatment equipment, for filtration and use as make-up to either the service water system or boiler feedwater system.

Feedwater will be used in the creation of process steam and for other uses where high purity water is required. As described in Section B.5.2.4, feedwater will be primarily supplied to the auxiliary boilers, gasifier and sulphur recovery plants.

Specific boiler feedwater treatment and wastewater treatment processes will produce wastewater streams with high total dissolved solids and concentrated ionic content. These streams are difficult to treat and recycle and will require disposal. In addition, the recycle pond contents will experience increasing levels of dissolved solids and other contaminants over time and the contents may require occasional blowdown. These continuous waste streams and periodic pond blowdown flows will be disposed of via on-site injection wells. Final engineering design will consider other water treatment options to further reduce the volume of water sent to disposal. It is expected that a total of three injection wells will be needed within the Project site boundaries. These on-site injection wells will be constructed and operated as EUB-approved class 1b water disposal wells. At maximum water cooling conditions, the continuous flow to the wells is approximately 23 m3/hour. After including several pond blowdown events, an estimated maximum wastewater volume of 800,000 m3 will be disposed of annually. The amount of wastewater disposal via deep well injection will be minimized in accordance with the NLP’s water management program for the Project. A separate regulatory application will be made for these required disposal wells.

Treatment processes will include primary filtration of raw water for use in utility (service) water system and boiler feedwater, additional boiler feedwater treatment, condensate return polishing, and possibly potable water treatment. Primary treatment will include processes such as clarification and membrane filtration. Boiler feedwater treatment will include RO and MBIX to create demineralized water, and addition of oxygen scavenger, amine, and phosphate as required to meet purity requirements specified by the American Boiler Manufacturers Association (ABMA) based on steam pressure class.



Condensate polishing will be undertaken to purify condensate formed by the collapse of generated steam to make additional steam.

Stormwater will be managed as discussed in Section B.5.3.3.

Domestic wastewater and sewage will be managed per Section B.5.3.1.

No use of groundwater is currently proposed for the Project.

B.5.2.3 Potable Water Supply and Distribution

During operation, potable water will be required to meet the needs of the workforce of approximately 300 people per day, with 1,000 persons per day present during periodic shutdowns. Using an average consumption of 135 litres per person per day, daily average demand was defined as 5.7 m3 per hour (m3/hr) with peak hourly and maximum daily demands of 22.5 m3/hr and 270 m3 per day respectively. As illustrated in Section B.5.2.2, several possible sources of potable water exist including direct purchase from the CRNWSC or filtration and “manufacture” of water from raw water sources. An alternatives review, coupled with discussions with CRNWSC, determined that the most appropriate potable water source involved an extension of the CRNWSC system to the Project site.

Potable water will be distributed to the Project after entering the Project site and passing through a meter and reduced-pressure backflow preventer located in the Water Treatment Building. Potable water will be supplied to building plumbing and drinking water systems and in-plant safety system and process consumers. Distribution will occur via pipeline network.

B.5.2.4 Boiler Feedwater/Condensate/Service Water Treatment

Make-up water for steam generation and process use in the Project will be provided from the raw water system and raw/fire water pond. The raw water will be initially pre-treated via flocculation, clarification and ultrafiltration with the filtered water directed either to the service water system or feedwater system.

B.5.2.4.1 Service Water

The service water system will receive water from primary treatment and will be used as required for Project maintenance and other non-potable uses. As the service water system will have low flow or stagnant sections, limited hypochlorite will be added to prevent bio-fouling.

JC


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B.5.2.4.2 Boiler Feedwater/Condensate

Further purification and treatment of water from primary treatment will occur in the feedwater treatment system, prior to use for steam generation and other uses. Effluent water quality from this treatment step will meet ABMA guidelines for purity based on pressure class. Such treatment and purification will be accomplished via a combination of reverse osmosis (RO) filtration followed by MBIX (deionization). The treated water will be deaerated and further chemically treated for corrosion protection of the boiler/steam circuit (Figure B.5.2.4.2-1).

Three RO/MBIX trains will be provided and the product water will be sent to the boiler feedwater storage tank. The system will operate on tank level control, with average and peak make-up water flow ranging from 144 to 225 m3/hr. These flows will be sent to deaerators in combination with returning condensate for removal of oxygen prior to entry into the auxiliary boilers, gasifier, SRU and other consumers.

Returning condensate (condensed steam) from both the steam turbine (condenser) and upgrader will be captured and stored in multiple condensate storage tanks, prior to being directed through a condensate polisher for removal of impurities. Prior to the polisher, the return condensate must be cooled to increase the impurities removal efficiency. The polisher effluent will either be discharged into a feedwater storage tank, for mixing with make-up water from RO/MBIX treatment system or will flow directly to the deaerators. Up to 80 percent of the water flow used for steam generation and process steam will likely be returned in the form of condensate.

Waste streams from the RO, consensate polisher, and boiler blowdown will be collected in a common wastewater tank and forwarded to the IWT plant for treatment before recycling. MBIX regeneration and cooling tower blowdown flow will be directed to a separate blowdown RO unit, with the RO permeate returned back to the cooling tower basin and RO blowdown directed to deep wells for injection. This blowdown flow stream will be minimized.

B.5.2.4.3 Chemical Feed

The chemical feed system for the boiler feedwater system will consist of bulk storage, dry feeder mix tanks, mixers and pumps. Each chemical feed tank will have two, 100 percent chemical feed pumps; one will be on standby. The pumps will be flow paced, that is, each will take a signal from a flow meter and the chemical feed rate will vary with the flow. The chemicals will be pumped directly into the feedwater, prior to entry into the auxiliary boilers and routing to process users.



The following chemicals will be injected, depending on influent water quality and chemistry:

liquid phosphate; and oxygen scavenger.

The chemical feed equipment for process injection locations will be located in the Water Treatment Building, with on-site chemical volumes stored in tanks or totes located within secondary containments and curbing. Chemical feed equipment for steam generation equipment injection will also be located in the Water Treatment Building, with tubing or piping used to distribute the chemicals to injection points. Chemicals will typically be stored in vessels less than 40 m3 in volume.

B.5.2.5 Process Cooling Water and Cooling Tower

A process cooling tower will be used to reject heat from returning upgrader process and ASU cooling water users to the atmosphere, to support water reuse. Make-up to the tower basin will be provided from the recycle water pond (filtered recycle water) and blowdown RO permeate, with tower basin blowdown based on the number of cycles of concentration of primary contaminants including suspended solids and silica. Tower blowdown will be treated via RO (Section B.5.3.2) prior to its return to the cooling tower basin as part of the overall water management program for the Project. The process cooling tower will be an eight to twelve-cell, mechanical draft, counter-flow cooling tower with 19,000 m3/h circulation/cooling capacity as a conceptual design basis (see Section B.5.2.5.1). The cooling tower will promote partial evaporation of the water flow through and, when combined with drift losses, requires continuous make-up.

B.5.2.5.1 Process Cooling Approach

For purposes of the Application, all water demand numbers herein are based on maximized use of water cooling for process equipment. However, NLP’s objective during detailed engineering will include increased consideration of air, glycol-based, closed cooling water, and other similar cooling systems. As an example, forced draft air (fin/fan type) coolers may be employed to primarily cool certain process streams with trim cooling by using water-cooled exchangers in an evaporative-type cooling process that consumes less water. Such consideration will subsequently reduce NSR withdrawal requirements to replace water lost in open cooling systems.

DRAWN

FIGURE No.

CHECKED

PROJECTDATE

SCALE

15 August 2006

PREPARED BY

LEGEND

B.5.2.4.2-1GMTDSW

F779

N/A

BLACK & VEATCH

TITLE

BOILER FEEDWATERPRE-TREATMENT

SCHEMATIC

NLP

_EIA

_DS

_FIG

_B52

421.

DW

GLa

Gra

ndeu

r, P

eter



The worst case for cooling water use will occur in the summer months when the ambient air temperatures are highest and this conservative case has been considered in the water demand requirements. There will be considerable reduction in the withdrawal amount during the cooler winter months because of lower evaporation from the wet cooling tower.

B.5.2.6 Ponds

Primary on-site ponds involved in the overall water (and wastewater) systems for the Project include the following pond: raw/fire water pond, stormwater pond, recycle water pond, and sediment pond. Preliminary area, as well as expected silt build-up, freeboard, and winter-time ice formation included in the sizing basis, are addressed below. A description of each pond and its normal operating status are provided in Table B.5.2.6-1.

Table B.5.2.6-1: Pond Inventory

Pond Description Normal Status Raw/fire water pond Clay lined, with banked side slopes;

located at southern end of property north of the NSR.

Pond is maintained at a minimal level above dedicated fire suppression water volume and with at least 12 hours storage for other Project demands.

Stormwater pond Clay lined, with banked side slopes; sized for 100-year storm intensity; located at southern end of property north of the NSR. Pond may be subdivided to support processing of waste waters.

Pond is maintained dry or at minimal seasonal contribution level

Recycle water pond Geosynthetic lined, with banked side slopes; sized for 100-year storm intensity; located at southern end of property north of the NSR. Pond may be subdivided to support processing of waste waters.

Pond is maintained within a normal operating range, to support water reuse.

Sediment pond Clay lined, with banked side slopes; located at southern end of property north of the NSR and north of Victoria Trail.

Pond is maintained dry or at minimal seasonal contribution level, via drainage to the NSR.

The ponds are shown pictorially in Figure B.4.1-1.

The raw/fire water pond and the recycle water pond will each be constructed to hold water for utilities and process uses. Both ponds will be lined with a compacted clay liner. The raw/fire water pond will be constructed with a surface area of 100,000 m2 with allowances for sediment (1 m), ice (1 m), freeboard (1.5 m) and live storage (2 m). The design will incorporate an allowance for 25,000 m3 of dedicated fire water storage and 260,000 m3 of raw water storage (approximately 10 days of non-fire water storage – volumes to be finalized during detailed design phase). The recycle water pond will



contain 114,000 m3 of water, with allowances for ice (1 m), freeboard (1.5 m) and live storage (approximately 2 m).

The stormwater pond will have an area of 130,500 m2 with a design depth accounting for sediment (1 m), ice (1 m), freeboard (1.5 m) and live storage (2 m). The volume will accommodate 170,000 m3 and will be maintained at a low level to allow for inflows of stormwater. This pond will be lined with a compacted clay liner.

B.5.2.7 Overall Water Balance

An overall water balance for the Project, on an annual average basis as well as for summer and winter peak conditions, was prepared to determine anticipated on-site pond sizes (storage), as well as to estimate the amount of make-up water needed from the NSR.

The overall water balance is illustrated in Table B.5.2.7-1.

Table B.5.2.7-1: Overall Water Balance

Overall Water Balance1 Flow (m3/h) Total demand from the NSR 1,228 Other water sources:

Developed area stormwater 0Water in feed 6

Total Inflows 1,234Water disposition:

Recycle water and feedwater losses to process 392Net evaporation/drift – process cooling tower 759 Net evaporation – ponds 20Blowdown of High TDS Waste Streams to Deep Wells 23Lost to products 15 Misc. Steam Cycle & Water Losses 25Water Discharge to the NSR 0

Total Outflows 1,234 Notes: 1. Average annual, calendar day basis (maximum NSR withdrawal case involving maximum

use of water cooling) with no consideration of stormwater recovery.

The total and average instantaneous demands from the NSR sum to 10,300,000 m3 per year and 0.34 m3/s, respectively. The total annual demand was calculated on the basis that developed area stormwater would be recovered and recycled; total stormwater for a



10-year dry year was utilized. As reported earlier, a peak instantaneous withdrawal rate of 1.2 m3/s is required for short-term pond filling and emergency fire events.

B.5.3 Wastewater

The major wastewater streams from the Project and the management and disposition of these streams are depicted in Figure B.5.3-1 and are described below.

Wastewater potentially bearing oils, greases, or other hydrocarbons and stormwater which may come into contact with hydrocarbons (developed areas), will be routed through either oil/water or oil/grit separators where they will be treated to remove such contaminants. Additional treatment means such as dissolved air/gas flotation, bio-treatment, and filtration will be considered in these waste streams prior to their discharge into the recycle water pond, or potentially as a slip-stream clean-up for the pond proper (see Section B.5.3.2).

High dissolved solids-bearing process streams (MBIX regeneration, cooling tower blowdown) will be treated via RO prior to reuse. Other blowdown streams will be treated via the IWT plant, prior to discharge back into the recycle water pond for reuse (see Section B.5.3.2).

Sour water streams will be stripped of NH3 and H2S in the SWS units and reused in the processes.

Process water blow down (grey water) from the Project will be collected, filtered, and pH neutralized (via the IWT plant), and returned to the recycle water pond for reuse (see Section B.5.3.2).

Stormwater from outside the developed area will be re-directed to natural drainage courses by appropriate grading measures (e.g., on-site berms, ditches, grading and culverts) (see Sections B.4.2 and B.5.3.3).

Domestic/sanitary wastewater and sewage will either be collected and treated on-site, or sent to a proximate municipal Wastewater Treatment Plant for processing and disposal (see Section B.5.3.1).

Periodically, water from the recycle water pond which cannot be recycled for use in cooling towers and other applications will be disposed of by deep well injection (see Section B.5.3.2).

All wastewater treatment systems will be designed to remove or neutralize contaminants from various process systems on-site, for the purpose of supporting wastewater reuse via recycling. The specific requirements of the treating systems will be developed during the detailed engineering phase as specific information becomes available from equipment licensors and final system designs. Additional descriptions are contained in the following sections.



B.5.3.1 Domestic/Sanitary Wastewater Management

Two primary alternatives were considered for the capture and safe disposal of domestic/sanitary wastes from the Project: (1) capture, treat, and recycle wastewater on-site using conventional treatment technologies, or, (2) capture and discharge such wastewater to a local municipality for proper treatment and disposal. Either alternative will satisfy AENV’s treatment standards and guidelines. This section describes the alternatives and describes the selected approach for the Project.

For the alternative of on-site treatment of domestic/sanitary wastes, preliminary treatment will include advanced Biological Nutrient Removal (BNR) in a bioreactor, high-rate clarifier for reliable initial BNR treatment and membrane protection, followed by membrane high-rate micro-filtration and finally ultraviolet (UV) disinfection. The membrane step will not be a substitute for the settling process, but it will remove micro-organisms and minor particulates, allowing for an even higher efficiency than conventional BNR processes. The final water quality parameters will be significantly better than regulated treatment requirements (Standards and Guidelines for Municipal Water, Wastewater and Storm Drainage Systems (2006)). Waste biological sludge will be digested aerobically, thickened, dewatered and taken to landfill or reused for beneficial reuse after composting by application for soil enrichment around the production facilities site. Odourous air will be treated internally. The final effluent water stream will be recycled to the recycle water pond, for reuse.

With respect to off-site disposal options, several local municipalities were considered for possible acceptance of the Project wastewater stream. Of these, the Town of Redwater’s existing system was found to be the closest receptor and discussions with Town officials ensued as to the feasibility of their system accepting Project wastewater. After confirmation that, following some improvements, the Town of Redwater could handle anticipated flows, this disposal method has been identified as the preferred option at this time. Primary selection criteria included avoiding capital cost for a treatment system, capability of the Town of Redwater system, and proximity of the Town’s Wastewater Treatment Plant. An on-site lift station will pump this wastewater stream to the extended Town force main. An emergency storage tank will be installed in the lift station to handle flows in the event of a system interruption (e.g., loss of electric power, line blockage).

DOMESTIC

INDUSTRIAL

INDUSTRIAL

STORM

JC


DRAWN

FIGURE No.

B.5.3-1CHECKED

PL

PROJECTF779

DATE


PREPARED BYIndustrial, Storm and Domestic WastewaterSchematic

NA

LEGENDTITLE



B.5.3.2 Industrial Wastewater Management and Treatment

A number of process, hydrocarbon-bearing, and blowdown wastewater streams will be collected and treated within the IWT plant in addition to those listed in Section B.5.3.1, as depicted in Figure B.5.3-1. These additional streams and their associated treatment processes are as follows:

a closed process sewer system will capture various Upgrader process and pipeline drains, and will transfer said fluid to the API oil/water separator for processing; recovered oils will be recycled for use through the slops tanks, with separated water treated in the IWT plant and recycled;

closed-loop drains from other process areas (e.g., gasifier, hydrocracker) will capture hydrocarbons and direct them to the slop tanks for processing; and

a product tank water draw-off system will capture connate, condensation, and other water that might form inside the tanks (Section B.5.8.2) and transfer this wastewater to either the API separator or contact stormwater pond, similar to stormwater collection/discharge (see Section B.5.3.3).

Treatment equipment in the IWT plant includes an oil/water separator, and an IWT system including equalization tank, flocculation tank, dissolved air flotation (DAF), anoxic/aerobic cell treatment, clarification, and filtration sub-processes. The API separator will be used to remove oils and other hydrocarbons from entering waste and wastewater streams, to support further treatment processes and to capture and recycle oils/hydrocarbons back into the Project. The effluent water stream from the API separator, coupled with influents from the gasifier blow down (grey water), and other blowdown/backwash streams, will be directed through the IWT plant. Effluent water from the IWT plant will have suitable characteristics for discharge to the recycle water pond, for reuse in the Project and other processes. Bio-sludge from the IWT plant and grit from the API separator will be disposed of off-site at a properly registered landfill. All IWT equipment will be housed in a building, located proximate to the API separator as shown on Figure B.4.1-1.

Wastewater discharged from the IWT plant will be directed to a dedicated cell polishing pond wherein the suitability of the water for reuse in the recycle pond can be established before such fluid is discharged there. Certain wastewater streams containing high TDS, which are not easily treated by conventional methods, and occasional blowdown from the recycle water pond will be directed to the disposal wells. During detailed engineering the NLP will strive to minimize the volume of water going to disposal wells.



B.5.3.3 Stormwater Management

Stormwater management during construction is discussed in Section B.4.2.

During operation, two streams of surface water runoff will be generated from the Project. Surface runoff from undeveloped areas will be directed to natural drainage courses or the sediment pond prior to discharge to the NSR, while surface runoff from developed areas will be directed to the stormwater pond. The balance of this section addresses stormwater associated with developed areas.

Stormwater collected on the site from developed areas but where contact with hydrocarbon products or spills is unlikely will be directed to the stormwater pond. Water collected from process and utility areas, where contact with hydrocarbons is more likely, will be directed through an oil/grit separator prior to discharge to the stormwater pond. The pond will also be equipped with a skimming system to capture hydrocarbons which may bypass the separator (e.g., high flow events) and a suitable liner system to ensure that water does not migrate into the region’s groundwater. Pond contents will normally be pumped through a fine sand media filter to the recycle water pond for reuse. Alternately, the pond’s contents may also be pumped through the API separator and IWT plant if higher levels of hydrocarbons or other contaminants are present.

The exterior surfaces of buildings and structures, paved or concrete areas within the Project site and other impermeable surfaces within developed areas of the Project site will generate runoff during storm events and snowmelt. Runoff from these areas will be directed to the stormwater pond by site grading, ditches, culverts, and pipelines. In process units where there is not enough gradient for gravity flow to the stormwater pond, the runoff water will be collected in an open sump and then will be pumped to the stormwater pond.

The product tank farm (Section B.5.8.2) will include impervious dikes and secondary containment systems engineered to meet EUB and AENV requirements for secondary containment. The areas inside the dikes will be sloped to a corner sump to collect rain or snow melt water. Following operator examination of containment contents through visual observation or testing, collected fluid will be pumped out using permanent forwarding pump(s) and will be directed to either the stormwater pond, if hydrocarbon-free, or to the API oil/water separator (Section B.5.3.2) if hydrocarbons are present. If the containment is water-free and full of hydrocarbons (such as from a tank spill or failure), such flows will be removed via vacuum or pumping and disposed of in on-site slop tanks (Section B.5.8.2) or other appropriate disposal locations.

All process areas will be equipped with fire water protection. In the event of a fire in any process unit, the fire water will be collected in the process area runoff drains and



directed to the stormwater pond. The drain system will be designed to accommodate fire water flows.

To the greatest extent practical, the water from this stormwater pond will be recycled to minimize the amount of raw water required from the NSR. The stormwater pond will be designed to handle a maximum water in-flow associated with a 1-in-100 year storm event, and the other ponds will consider direct stormwater entry. For storm intensity greater than a 1 in 100 year event, the ponds will be configured to discharge overflow water to the NSR. In addition, stormwater management practices during significant Upgrader process outages or unusual events such as extreme rainfall for an extended number of calendar days may also require short-duration discharge of pond contents to the NSR.

B.5.4 Fuel Gas Supply and Distribution

This section identifies the natural gas requirements for the Project, and describes gas delivery and distribution. Natural gas will be required for steam generation, process use, and building heating, although synthetic or fuel gas produced in the Project process will be preferentially collected, treated, and combusted over natural gas.

Natural gas will be principally consumed as a back-up supply for steam generation (auxiliary boilers) and as a part of necessary gas supply to process equipment and building heating. A small amount of natural gas will also be required for flare pilots and may be utilized for blanketing hydrocarbon tanks and process vessels.

B.5.4.1 Natural Gas Demand

Natural gas requirements of Project to meet steam, process, and heating needs are listed in Table B.5.4.1-1. The data in the table reflect average hourly natural gas usage for normal operating conditions and upset acid gas flaring conditions as described in Section B.5.8.5.3. All values are presented on a calendar day basis, and are based on inputs received on the Project conceptual design and preliminary flare design. The data do not reflect peak gas consumption during periods when syngas is not available. Similarly, this table does not reflect the natural gas required for heating during cold weather or for tank blanketing processes, as these are minor demands.



Table B.5.4.1-1: Natural Gas Requirements

Inputs Natural Gas Requirements – Normal Phase 1/2 Operations

(kg/calendar day, at Lower Heating Value1) Scenario Auxiliary

Boilers and Steam

Generation

Infrastructure (Bldg. Heating)

Upgrader Process Demand and Flares

Total Normal Gas Demand

Normal operating conditions - Winter 144,000 24,000 584,000 752,000

Normal operating conditions - Summer 144,000 4,800 584,000 732,800

Acid Gas Flare Enrichment ( Plant upset conditions)

411,000 kg/hour2

Notes. 1. Based on an LHV of 37.7 MJ/m3 and density of 0.72 kg/m3 (specific gravity = 0.59) 2. See Section B.5.8.5.3

B.5.4.2 Natural Gas Supply and Distribution

Natural gas to the Project site will be provided by third parties. At the present time, natural gas is provided to the Fort Saskatchewan area by one principal supplier, ATCO Gas, which has several existing mains in the vicinity of the Project site. Short extension of an existing natural gas supply header to the Project site will provide needed natural gas. The incoming high-pressure gas will be metered, conditioned, reduced in pressure and distributed to users. All low-pressure natural gas associated with facility heating will be odourized for personnel safety requirements; much of the high-pressure gas used in power generation will not be odourized but handling equipment and pipelines will be located in fenced areas and away from the site workforce.

A basic layout of the natural gas supply system is contained in Figure B.5.4.2-1. Gas characteristics, as reported by the anticipated gas supplier to the Project, are listed in Table B.5.4.2-1.



Table B.5.4.2-1: Project Natural Gas Characteristics

CONTENTS

Symbol Element Vol. % H2 Hydrogen 0.00 CH4 Methane 96.87 H20 Water 0.00 H2S Hydrogen sulphide 0.00 He Helium 0.00 N2 Nitrogen 0.93 C2H4 Ethylene 0.00 C2H6 Ethane 1.06 C3H6 Propene 0.00 CO2 Carbon dioxide 0.68 C3H8 Propane 0.32 C4H8 I-Butene 0.00 iC4H10 Iso-Butane 0.07 nC4H10 N-Butane 0.07 iC5H12 Iso-Pentane 0.00 nC5H12 N-Pentane 0.00 C6+ C6+ 0.00 Total 100.00 LHV Low Heating Value (average) 38.39 MJ/m3 SG Specific Gravity (average) 0.59 Notes:

1. All values are percent by volume (vol %) except as indicated. 2. Values in Table B.5.5-2 were provided as a representative gas sample by ATCO Gas. Gas

characteristics will change over time.

DRAWN

FIGURE No.

B.5.4.2-1CHECKED

GMTDSW

PROJECT

F779DATE

SCALE

15 August 2006

PREPARED BYBLACK & VEATCH

N/A

NATURAL GAS SUPPLYSCHEMATIC

NLP

_EIA

_DS

_FIG

_B54

21.D

WG

LaG

rand

eur,

Pet

er



B.5.5 Steam and Power Demand

Upgrader operations require a significant amount of electrical power and process steam to facilitate the conversion of diluted bitumen to SCO. This Project involves the gasification of asphaltene product recovered in the fractionation of bitumen into a hydrogen-rich synthetic gas, which will be further processed in a PSA to create a saleable hydrogen by-product. Section B.6 contains a discussion of the alternative energy/generation cases that were examined for the Upgrader.

Process steam will be required at the following pressure levels:

4,500 kPag (high pressure, superheated); 4,500 kPag (high pressure saturated); 1,050 kPag (medium pressure); and 400 kPag (low pressure).

High pressure process steam will be primarily generated by the gasifier and auxiliary boilers at superheated conditions, and by the SRU (waste heat boilers) and hydrocrackers (heater convection) at saturated conditions; both medium and low pressure steam will be generated via letdown of high pressure steam in consumers and via high pressure and medium steam header letdown stations, respectively.

Table B.5.5-1 illustrates the steam demand requirements at the high pressure level; to support this demand and lower-pressure steam demands, three 90 tonne per hour auxiliary boilers will operate at part-load to generate the balancing steam flow to sustain an overall balance. A large percentage of this steam is captured as condensate and either reused within the process lines as condensate or returned to the boiler feedwater system (Section B.5.2.4) for reuse in steam generation. Figure B.5.5-1 illustrates steam distribution on the Project site. These flows and distribution system are preliminary and for illustration purposes only; they will be further optimized in detailed design.

Table B.5.5-1: Project Steam Demand- High Pressure Steam

Consumer Normal Demand, kg/hr Steam Supply Source

Equipment Drives 63,500 Superheated, 4,500 kPag header

Hydrogen Recycle Compressors

120,700 Superheated, 4,500 kPag header

SRU Air Blowers 38,600 Superheated, 4,500 kPag header

Letdown to 1,050 kPag Steam 8,000 Superheated, 4,500 kPag



Consumer Normal Demand, kg/hr Steam Supply Source Header (superheated) header

Letdown to 1,050 kPag Steam Header (saturated)

49,000

Saturated, 4,500 kPag header

Upgrader Preheaters, Reheaters

69,500 Saturated, 4,500 kPag header

Totals

Superheated, 4,500 kPag Header 230,800

Header supplied by Auxiliary Boilers, Gasifier, Hydrocracker Heaters

Saturated, 4,500 kPag Header 118,500 Header supplied by SRU Waste Recovery Boilers

The three auxiliary boilers will principally combust “mixed gas”, which is a combination of the remaining synthetic gas generated in the Project process and natural gas make-up. The primary constituents of this mixed gas are: methane, carbon oxides, nitrogen, ethane, i-butane, propane, hydrogen and various smaller fractions. The resulting lower heating value (LHV) of the gas is 22 MJ/m3. This gas does contain sulphur compounds which will be oxidized to sulphur dioxide in the burners of the auxiliary boilers. As the auxiliary boilers are critical to start-up, shutdown, and emergency conditions, they will be fed from highly reliable electric power sources.

Primary consumers of electric power include those components listed in Table B.5.5-2; the table lists estimated power demand at full Upgrader capacity after Phase 2 is operational.

Table B.5.5-2: Project Electric Power Demand

Component Unit Owner Demand / Level

DRU/VDU 10 3.6 MW operating at 13.8 kV SDA Unit 20 4.9 MW operating at 13.8 kV HU 30 37.6 MW operating at 13.8 kV SRU 40 2.9 MW operating at 13.8 kV Gasifier 50 74 MW operating at 13.8 kV ASU 60 112 MW operating at 34.5 kV stepped down to 13.8 kV Balance-of-Plant n/a 23 MW operating at 13.8 kV Losses n/a 3 MW operating; at various levels Total Demand 261 MW operating

DRAWN

FIGURE No.

B.5.5-1CHECKED

GMTDSW

PROJECT

F779DATE

SCALE

15 August 2006

PREPARED BYBLACK & VEATCHSTEAM

DISTRIBUTION SCHEMATICN/A

NLP

_EIA

_DS

_FIG

_B55

11.D

WG

LaG

rand

eur,

Pet

er



B.5.6 Electric Power Supply and Distribution

The Project site will be interconnected to the AIES via 240 kV circuits provided by the TFO. This interconnection will support full import of required electric Project power and transformation down to consumers. An application for limited on-site power generation equipment, on-site 138 kV substation, and industrial system designation under EUB Directive 028 will be included as a separate application.

B.5.6.1 High Voltage Substation and Grid Connection

The on-site location of the 138 kV substation and interfacing corridors for high voltage electric power lines were shown in Figure B.4.1-1. An electrical schematic of the proposed 138 kV substation, showing interface with the AIES and high voltage power distribution is included in Figure B.5.6.1-1. A separate application under the EUB Directive 028 will be made. A limited amount of electrical power is generated (estimated to be between 5 and 40 MW) on site during normal operation, which is far below the normal operating power demand of 261 MW. As such, virtually all power will be imported off of the 240 kV AIES. Per discussions with the Alberta Electric System Operator (AESO), the existing 240 kV circuits in the Fort Saskatchewan area are being modified to support new industrial growth in the region including this Project. It is presently envisioned that two 240 kV AIES circuits will support the Project power demands (one entering, one exiting).

Within the substation, a 138 kV ring bus equipped with circuits breakers and step-down transformers will be used to distribute power to primary Project users. Primary high/medium voltage distribution to Project equipment will be at 34.5 kV, 13.8 kV, and 4160V power levels, with buses generally double-fed to improve reliability. Further discussion on AC distribution is included in Section B.5.6.2.

As part of the overall Project, an existing 138 kV circuit that crosses the Project site in a north-south direction must be relocated by the TFO. A corridor for this transmission line will be created along the west property boundary.

B.5.6.2 AC Power Distribution

Alternating current (AC) will be distributed throughout the Project site at voltage levels including 34.5 kV, 13.8 kV, 4160V, 600V, and lower voltages to service process equipment, lighting, heat tracing, administrative, and other users. All AC power distribution will be in accordance with the Canadian Electrical Code. The source for virtually all distributed electricity in the Base case is from the 138 kV substation and AIES.



AC distribution within the Project will be accomplished via conventional means, including switchgear, motor control centres, disconnect switches, panelboards, and cable.

B.5.6.3 DC Power Distribution

Direct current (DC) systems employed at the Project site will consist of a 125 volt DC (VDC) system powered by the station battery located in the Electrical Building providing DC service to all facility users located in close proximity.Local, distributed DC battery and power supply systems will typically provide a back-up power to remotely located equipment in the case of failure of primary power supply. Project batteries will be installed and maintained per industry guidelines to avoid any adverse environmental effects (e.g., local acid spills). Other 125 VDC systems will be located in distributed power distribution centres (PDCs) on-site.

B.5.6.4 Emergency Power Generation and Distribution

Emergency power generation and distribution will be in the form of two systems: uninterruptible power supply (UPS, low voltage AC); and emergency diesel generators (EDGs). A central UPS will be located in the Electrical Building and will power all critical loads including Administration Building and Upgrader Operations Complex lighting and receptacles, ICS hardware and other local control systems including those associated with emergency shutdown, auxiliary boiler and air compressor controls, security systems, computer systems, and other loads found critical during the Project engineering phase. A limited number of distributed UPS systems may also be employed local to critical equipment and controls which are remote from the Electrical Building.

Diesel generators will be employed to service other critical electric users at the Project site, upon loss of normal power. These critical loads include emergency lighting, pumps required for boiler feedwater and boiler operations, heat tracing, and lubrication supply pumps on critical rotating equipment. The number of emergency generators, their location, and expected operations will also be confirmed during the Project detailed engineering phase.

Certain pumps and equipment in the Project will also be considered for steam or diesel drives to reduce the loss of availability of desired subsystems, including compressed air and water supplies.

DRAWN

FIGURE No.

B.5.6.1-1CHECKED

PROJECTF779

DATE

SCALE

15 August 2006

PREPARED BYBLACK & VEATCHPOWER DISTRIBUTION

SCHEMATIC

NLP

_EIA

_DS

_FIG

_B56

11.D

WG

LaG

rand

eur,

Pet

er

N/ABLN VB



B.5.6.5 Lighting, Heat Tracing and Other Services

Miscellaneous electrical systems that will be employed at the Project site will include lighting, heat tracing, grounding, lightning protection, cathodic protection, and communications systems.

Site lighting, and lighting along Project roadways and elevated on buildings and process equipment to support security, operations, and maintenance, will be required. To minimize off-site effects caused by sky glow, local light trespass and glare, lighting will only be provided as required to support high traffic areas, security checkpoints, and facility areas where operations and maintenance attention is regularly needed. In general, high-pressure sodium (HPS) lighting fixtures (luminaires) will be used for exterior lighting in the operating Project, although other luminaire sources (e.g., metal halide, fluorescent, low pressure sodium) will be considered based on application, cost, energy consumption, and quality of light needed. Volume 2, Section E.14 Light contains supplemental information on site lighting including anticipated intensity and illumination levels and mitigative measures to be taken to reduce offsite effects.

Electric heat tracing and, in some instances, hot oil fluid or steam supplies, will be used for heat tracing and freeze protection of process equipment in the Upgrader, product tank farm, and power/steam generation systems, as well as other local piping systems and processes. Grounding and lightning protection systems will comply with the Canadian Electrical Code and applicable Canadian Standards Association documents, based on soil resistance and Project site isoceraunic level. The scope of protection will be identified in the detailed design engineering phase.

B.5.7 Instrument and Control Systems

Primary Project process, system, and equipment control will be accomplished with an ICS (Section B.5.7.1), with field controls and instrumentation (Section B.5.7.2) providing both local operating capability and feedback to the ICS.

B.5.7.1 Integrated Control Systems

The ICS for the Project will provide overall control for operation of the various Upgrader processes, steam and power generation equipment, and balance-of-plant systems, while possessing sequence-of-events (SOE), annunciation, and data acquisition and handling functions (DAHS) for support of plant operations. Additional capabilities will be considered in the ICS, including interface with supervisory controls and data acquisition (SCADA) and telecommunications with the complementary Northern Lights Mining and Extraction Project operations, third party interconnecting pipeline operations and status, monitoring of intermediate products and feedstock flows to third parties, and integration



of site security, fire protection, building automation and controls, process area surveillance, and power quality.

The ICS will be configured such that no single failure will result in loss of process control, safety, or operator interface. The ICS will include an integral safety instrumented system (SIS). The ICS will consist of centralized HMI and master control components located in the central control room in the Upgrader Operations Complex, interconnected to distributed control system (DCS) hardware and marshalling cabinets located in unit monitoring buildings (UMB), and field devices through a data highway and network. Project operators will be housed in thecentral control room, with roving staff used for field monitoring and intervention.

UPS will be provided for ICS components.

B.5.7.2 Local Controls and Instrumentation

Local controls will consist of control and instrument components associated with specific equipment or process lines which perform a specific function and for which control equipment is integrated. Local controls such as programmable logic controller (PLC) based systems supplied with packaged mechanical equipment will interface with the central control room. Local control systems include Continuous Emissions Monitoring Systems (CEMS) used to monitor air emissions from applicable stacks, and fire detection system. Field instrumentation will be installed in process and utilities systems to allow for remote monitoring and control, as well as for local operator use. Such devices will either interface with the central control room directly or report through a UMB.

B.5.8 Other Auxiliary Systems

The following auxiliary systems and utilities each perform an important duty in the overall production of SCO from a diluted bitumen feedstock, while minimizing potential adverse effects on the environment.

B.5.8.1 Compressed Air and Nitrogen Supply

Balance–of-plant systems at the Project site will include a centralized Compressed Air Supply and Distribution System. The Compressed Air Supply and Distribution System will generate air for miscellaneous users including air drops and hand-tool supply connections for facility maintenance, and instrument quality compressed air for instrumentation, valve controllers, and other users needing low dewpoint (dry) air supply. Both instrument and utility air streams will be produced by electric or steam driven air compressors (with a connection for a back-up diesel air compressor). The discharge will



be directed to either the instrument air header or the utility air header. The air compressor discharge will be dried to instrument air specifications by passing the air through heatless air dryers. Preference will be given to the instrument air by closing the utility air header valve on pressure decay. Both air streams will be supported via use of air receiver tanks located both at the production equipment and proximate to users of high demand. The total compressed air supplied by the system will be 12,000 m3/hr (peak), with an estimated average flow rate of 10,000 m3/hr.

The centralized compressed air equipment will be located in the Water Treatment Building. There may be a need for additional compressed air at remotely located equipment. Such remote areas will be furnished with appropriately sized compressor(s), with a dryer(s), receiver(s), pressure reduction, and other infrastructure as needed by the remote process. Final system configuration will be established during the Project engineering phase.

Nitrogen will be used continuously and intermittently for equipment flare, and pipeline purging, and for blanketing certain hydrocarbon tanks.. Nitrogen will be recovered in the ASU as a liquid, and stored in a common, on-site pressurized storage vessel. This storage vessel will also be outfitted for receipt of nitrogen from third-party truck or high pressure cylinder charge, and will be centrally located near the Water Treatment Building. Nitrogen will be distributed on site in either high pressure or low pressure distribution pipelines, as required by the end user. Final system configuration will be established during the Project engineering phase.

B.5.8.2 Product Tank Farm and Pipelines

The diluted bitumen will be received via a third party pipeline and stored in the on-site Product Tank Farm prior to upgrading. The diluent used to lower viscosity of the bitumen for pipeline transmission will be extracted at the Project and returned to the Northern Lights Mining and Extraction Project also via a third party pipeline. Approximately three-days of on-site storage will be provided in the Product Tank Farm for both diluted bitumen and diluent to accommodate outages in either the Project, or the Northern Lights Mining and Extraction Project, or the interconnecting third party pipelines.

The Product Tank Farm will also contain SCO produced in the Project process, prior to its shipment to downstream customers off site. The Product Tank Farm will also contain intermediate tanks and spheres for the temporary storage of gas oil, diesel, vacuum distillate bottoms, butane, pentane, and propane streams from the Project, as these are used or generated in the upgrading process.



Two product slop tanks will be provided for storage of intermediate or finished synthetic oil that do not meet specifications for downstream processing or transport off site, as well as to receive oil recovered in the API separator. Slop tank contents will be pumped back to the DRU/VDU for further processing.

Table B.5.8.2-1 is a summary of these product and intermediate tanks. A preliminary schematic layout of the Product Tank Farm is provided in Figure B.5.8.2-1.

Table B.5.8.2-1: Process Storage Tank Summary

Fluid Units Diluted Bitumen Diluent AGO VGO Diesel VTB DAO SCO LightSlop Heavy.

Slop

Tank Number(s) #

D-001A D-001B D-001C

D-002A D-002B D-003

D-004A (LVGO) D-004B (HVGO)

D-005 D-006 D-007

D-008A D-008B D-008C D-008D

D-009 D-010

Diameter m 59 41 32 32 32 32 32 59 21 21 Height m 14.63 14.63 14.63 14.63 14.63 14.63 14.63 14.63 14.63 14.63 Total Volume kB 243 122 74 74 74 74 74 243 31.9 31.9

Working Volume kB 200 100 60 60 60 60 60 200 25 25

Unavailable Volume kB 43 22 14 14 14 14 14 43 6.9 6.9

Sizing Basis (process) Days 3 3 -- -- --

-- -- 3 N/A N/A

Shell Type --- Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Vertical Cylinder

Roof type --- IFR or Fixed IFR IFR Fixed IFR Fixed Fixed IFR IFR IFR

Vapour recovery (Note 10)

---

N2 Blanket

(as required)

Yes, to process

or N2 blanket

No

N2 Blanket

(as required)

N2 Blanket

(as required)

No

N2 Blanket

(as required)

N2 Blanket

(as required)

N2 Blanket (as

required)

N2 Blanket

(as required)

Notes # 1 2 3 3



Table B.5.8.2-1: Process Storage Tank Summary (Continued)

Fluid Units Propane Bullet Butane / Pentane Sphere (SDU Solvent)

Butane Sphere (Product)

Tank Number # V-001A / V-001B V-002 V-003A / V-003B / V-003C Diameter M 4 14 14 Height M 12 N/A N/A Total Volume kB 1 9 9 Working Volume kB 0.9 7.5 7.5 Unavailable Volume kB 0.1 1.5 1.5 Sizing Basis Days Process Process Process Shell Type --- Horizontal Cylinder Round (sphere) Round (sphere) Roof Type --- N/A N/A N/A Vapour Recovery --- No No No Notes # 5 6 7

Notes: 1. Diluted bitumen receipt tanks designed to fill from third party pipeline, while feeding certified

diluted bitumen to Upgrader DRU/VDU for processing. 2. Diluent shipping tanks designed to fill from Upgrader DRU (recovered diluent from diluted

bitumen), while discharging to third party pipeline for return transport to the Northern Lights Mining and Extraction Project.

3. Start-up, off-spec or shut-down tank use. 4. Materials per API 650 for ambient temperatures as low as -45.5°C (-43°C is project design

temperature). 5. Propane bullet for storage of final product for sale/export. 6. Sphere for storage of butane and pentane for emergency/shutdown purposes. 7. Butane Sphere for storage of final product butane for sale/export. 8. IFR is “internal floating roof” with appropriate device seals to limit fugitive emissions. 9. N/A is not available 10. Vapour recovery selection (e.g. nitrogen blanketing, vapour recovery system, others) will be

confirmed during detailed design

Product fluids will be stored on-site in field-erected, above-ground, vertical cylinder steel tanks complying with the Alberta Fire Code, American Petroleum Institute Standard 650, EUB Directive 55 Storage Requirements for Upstream Petroleum Industry, and Canadian Council of Ministers of the Environment (CCME)-published environmental guidelines. Final selection of tank roof and vapor control systems will be accomplished in the Project engineering phase. The tanks will be installed in lined secondary containment (earthen berms). Precipitation entering the secondary containment will be collected and discharged to the stormwater pond via pumping after verification by the operator that such fluid is not oil-bearing or following clean-up. Water observed bearing hydrocarbons will be directed to the separator for processing at a controlled flow rate.

DRAWN

FIGURE No.

B.5.8.2-1CHECKEDGMTDSW

PROJECTF779

DATE

SCALE

15 August 2006

N/A

PREPARED BYBLACK & VEATCHPRODUCT TANK FARM

SCHEMATIC

NLP

_EIA

_DS

_FIG

_B58

11.D

WG

LaG

rand

eur,

Pet

er



B.5.8.3 Other Storage Tanks

Table B.5.8.3-1: Storage Tanks

Tag No. Description Location Type of Tank Size of Tank Volume Material

Type Contents

Stored Max True Vapour Press

Type of Vents

Fugitive Emission Control

Corrosion Protection

Type of Secondary

Containment

Method of Leak

Detection (Note 1 & 2)

Hydrocracker

D - 3101 Wash Water Break Tank

Above Ground

Vertical Storage

Tank 3.1 M High x

1.6 M Dia 6.3 Cu. Meters CS Water 0 Atom. N/A Cathodic None Diked-

visible

D - 3201 Wash Water Break Tank

Above Ground

Vertical Storage

Tank 3.1 M High x

1.6 M Dia 6.3 Cu. Meters CS Water 0 Atom. N/A Cathodic None Diked-

visible

V 2 Req'd Amine Sump Below Grade Drum TBD TBD CS-

Coated Amine Atmos.. Vent to flare Vent to flare Cathodic Concrete

vault TBD

V 2 Req'd Hydrocarbon Drain Tank

Below Grade

Closed Drain Drum TBD TBD CS HC &

Water 10 psi (est)

Vent to flare Vent to flare Cathodic Concrete

vault TBD

Sulphur Complex

D - 4001A/B Sulphur Storage Tank

Above Ground

Vertical Storage

Tank 13 M High x

18 M Dia 5200

Tonnes CS Molten sulphur

Atmos. (liquid) Atmos. Open to Atom. Corrison

allow. None Diked-visible

D - 4101 Feed

Preparation Storage Tank

Above Ground

Vertical Storage

Tank 15.6 M High x

24.4 M Dia. 45K

Barrels CS Sour water

N2 blanket Atmos. N2 blanket Corrison


D - 4201 Feed

Preparation Storage Tank

Above Ground

Vertical Storage

Tank 15.6 M High x

24.4 M Dia. 45K

Barrels CS Sour water

N2 blanket Atmos. N2 blanket Corrison


D - 4301 Amine Make-up Storage

Tank Above Ground

Vertical Storage

Tank 9.2 M High x

5 M Dia. 1100

Barrels CS Amine N2 blanket Atmos. N2 blanket Corrison


PK - 4400 Sulphur Pit #1 Package

Below Grade

Acid Resistant Concrete

22 m x 5 m x 4.2 m Deep

830 Tonnes

Acid Resista

nt Concret

e

Molten sulphur

Atmos. (liquid) Atmos. Educted to

incinerator yes None TBD



Tag No. Description Location Type of Tank Size of Tank Volume Material

Type Contents

Stored Max True Vapour Press

Type of Vents

Fugitive Emission Control

Corrosion Protection

Type of Secondary

Containment

Method of Leak

Detection (Note 1 & 2)

PK - 4501 Sulphur Pit #2 Package

Below Grade

Acid Resistant Concrete

22 m x 5 m x 4.2 m Deep

830 Tonnes

Acid Resista

nt Concret

e

Molten sulphur

Atmos. (liquid) Atom. Educted to

incinerator yes none TBD

V 4101 Sour Water Sump

Below Grade Sump 2.6 M D x 7.5

M H 40 Cu. M CS-Coated

Sour water Atmos. None Diked-visible Corrison

allow. Concrete

vault TBD

V 4201 Sour Water Sump

Below Grade Sump 2.6 M ID x 7.5

M Deep 40 Cu. M CS-Coated

Sour water Atmos. N2

blanket Educted to incinerator

Corrison allow.

Concrete vault TBD

V 4301 Amine Sump Below Grade Sump TBD 300

Barrels CS-

Coated Amine Atmos. N2 blanket

Vent to acid gas flare

Corrison allow.

Concrete vault TBD

DRU /VDU

V 1 Req'd Amine Sump Below Grade Drum TBD TBD CS-

Coated Amine Atmos. Vent to flare Vent to flare Cathodic Concrete

vault TBD

V 1 Req'd Hyd. Carbon Drain Tank

Below Grade

Closed Drain Drum TBD TBD CS-

Coated HC & Water

10 psi (est)


vault TBD

SDA Unit

V 1 Req'd Hyd. Carbon Drain Tank

Below Grade

Closed Drain Drum TBD TBD CS-

Coated HC & Water

10 psi (est)


vault TBD

Oily Water Sewer

Oily WaterSump

Below Grade Sump TBD TBD TBD

Comtiminated HC & Water

Atmos. Atmos. TBD TBD TBD TBD

NOTES: 1. Alarms are provided to avoid overfill for all installations. Adequate pumping facilities and Vacuum truck connections TBD: To be determined are installed at each location. N/A: Not Applicable 2. Regular inspection of vessels will be done on a planned maintenance basis to insure integrity



Major hydrocarbon spills will be recovered via vacuum truck. The product tank farm will also house appropriate metering for custody transfer/certification and commercial settlement, and level detection to allow proper management of vessel contents. Diluent, diluted bitumen, and SCO pipelines will be routed in dedicated corridors from the product tank farm to on-site interfaces at the property boundary with third party pipelines. These pipelines will either be routed below grade or on above ground sleeper foundations, and will typically be of welded construction.

Fugitive emissions from these tanks and pipeline fittings will be minimized; these air emissions are further addressed in Section B.7.4.

B.5.8.4 Fire Protection

General fire protection for the Project will consist of integrated fire detection systems, dedicated fire suppression systems, and an underground pipeline system serving hydrants and above-ground distribution systems (e.g., dry pipe deluge stations) for general water-based suppression. Upgrader process areas, the product tank farm, and buildings will have fire protection specific to the needs and applicable codes and standards, including the Alberta Fire Code, for their particular hazards. In general, with the exception of buildings and enclosures housing computer and control systems (inert gas suppression) and product tanks (foam), suppression will be provided by water supplied by dedicated pumps and dedicated water volume contained in the raw/fire water pond. This pond volume is maintained via periodic supply of make-up from the NSR; in the event of a fire of longer duration and flow rate than the design case, it will be possible to replenish the fire water volume via river water intake pumps operating at short-term peak flow rate. A schematic of the system is contained in Figure B.5.2.1.5-1.

Water needed on infrequent basis to suppress fires on Project property will be supplied via electric (primary and jockey) and diesel-driven (back-up) fire pumps, discharging to a common underground header. This header system will provide a reliable source of pressurized water for fire suppression throughout the administration area, Upgrader process area, product tank farm, and other areas. The required volume of water to be maintained on-site at all times, and specific flow rate and duration, will be confirmed in accordance with the Alberta Fire Code, insurance carrier request, and industry standard practice (as published by the National Fire Protection Association and others). Water contained in this header system will be continuously maintained under pressure by a jockey pump such that it is immediately available for use.

Fire monitors (hydrants with spray nozzles) and conventional hydrants with hose stations, supplied from an underground, fire water ring header, will service most of the process plant areas and facilities, with appropriate branches to building-internal systems and the product tank farm system. Further analysis will be completed during the detailed



engineering phase to identify other fire suppression needs. Water used in extinguishing a fire in process areas will be captured in the stormwater collection system and ultimately routed back to the recycle water pond.

B.5.8.5 Flare Systems

Three independent vent systems with flare stacks are provided for the safe disposal of gases created during upset or emergency operating conditions within Upgrader processes. Aside from active pilots in each flare, these vent and flare systems are anticipated to operate very infrequently. Flare system design criteria are based on worst-case design basis events typically in which the contributing process equipment is rapidly stopped during operation at peak condition from a process fault or utility failure (e.g., loss of off-site power supply). Each flare system may also operate at flows less than worst-case as a result of other transients at duty cycles less than design, such as during individual unit shutdown and depressurization events. Flaring events in each system will be infrequent in nature (greater than annual return periods anticipated) and short in duration (typically less than two hours). Most flare events cannot be planned in advance.

During normal Upgrader operations, the pilot burners (two to four burners per flare) in each flare will be lit and will combust natural gas at very minor flow rates (less than 300,000 Btu per hour per stack). These pilots must stay lit such that ensuing venting gas flow may be instantaneously lit following a transient or initiating event. Flare emissions were accounted for in the Section B.7 air emissions analysis. Nitrogen purge gas will be utilized in the flares and in the vent header systems to reduce the risk of explosive gas build-up prior to a venting event.

The vent headers connecting process equipment to each flare will have knock-out drums situated upstream of the flare to capture fluids and hydrocarbons in the discharge flows, purge gas systems to purge the flare stacks and vent piping up to flare tip, and suitable flare ignition and control systems. The two hydrocarbon flares will also be equipped with water seals at the flare bases to further reduce the possibility of combustible gas formation in the vent system. These features are illustrated in Table B.5.8.5.3-1. Flare locations are shown in the Site Plan Drawing, Figure B.4.1-1.

B.5.8.5.1 Low Pressure Hydrocarbon Flare

The Low Pressure Hydrocarbon Flare will serve numerous process lines and towers throughout the primary and secondary upgrading areas as well as utilities and offsites, providing a path to vent combustible gases during transient operating and shutdown events within each line/tower and worst-case events. Air emissions, flare sizing, and ground-level sterile (controlled access) zones around the flare base were all computed



on this basis. Detailed engineering design will consider optimized flare burner tips which may support adjusting the overall stack height and improved combustion.

B.5.8.5.2 High Pressure Hydrocarbon Flare

The High Pressure Hydrocarbon Flare will principally serve the two hydrocrackers and associated depressurization events. The worst-case flow is based on both hydrocrackers depressurizing at the same time (rare event). Air emissions, flare sizing, and ground-level sterile (controlled access) zones around the flare base were all computed on this basis. Detailed engineering design will consider optimized flare burner tips which may support lowering the overall stack height and improved combustion.

B.5.8.5.3 Acid Gas Flare

The Acid Gas Flare will serve the SRU and two parallel sulphur recovery lines therein. The worst-case vent flow is produced by a simultaneous trip of both recovery trains, such as may be caused by total loss of power to equipment operating at peak conditions (rare event). Air emissions, flare sizing, and ground-level sterile (controlled access) zones around the flare base were all computed on this basis. Alternative arrangements, including piggy-backing the Acid Gas Flare alongside the high pressure hydrocarbon flare to a higher exhaust point or use of a ground-level incinerator and exhaust stack, will be examined during detailed engineering design.

Preliminary sizing basis and air emissions modelling found that the only flare solution that can achieve EUB Directive 060 criteria based on postulated H2S in the acid gas involves significant addition of lift gas (natural gas enrichment/lift), as reported in Table B.5.4.1-1. Verification of flare functionality and confirmation of the conceptual flare design reported herein will be undertaken during detailed engineering design.



Table B.5.8.5.3-1: Flare Summary

ID Tag Description Site

Location and Base

Elevation

Tip Height (m AG)

Flare Dia. (m)

Exit Velocity

(m/s)

Gas Inlet

Temp (0K)

Notes

59-04-X-001 High Pressure Hydrocarbon Flare

N 5,972,225 E 363,890 630 mASL

70 1.83 461 449 Elevated guy-wired pipe stack with continuous pilot (four burners), smokeless to 15% of peak design flow. Carbon steel.

59-04-X-002 Low Pressure Hydrocarbon Flare

N 5,971,980 E 363,880 630 mASL

70 1.06 65 366 Elevated guy-wired pipe stack with continuous pilot (three burners), smokeless to 15% of peak design flow. Carbon steel.

59-04-X-003 Acid Gas Flare N 5,972,470 E 363,900 630 mASL

70 1.06 146 331 Elevated guy-wired pipe stack, continuous pilot (two or three burners), smokeless, self-inspirating. Stainless steel.

NOTES: 1. Design per EUB Directive 060, API RP520 and 521, API Std. 537, GASA, Alberta Ambient Air Quality Objectives. 2. Velocity and temperature data provided for maximum design exhaust gas case. 3. Abbreviations: mASL = elevation in metres above sea level; AG = above grade elevation.

B.5.8.6 Equipment Protection

Utilities equipment will be stored in a series of buildings at the Project site for environmental protection, noise mitigation, security, and other reasons, as noted in Table B.5.8.6-1. Further definition of building information was provided in Section B.4.5.

Table B.5.8.6-1: Utility Housing Summary

Utility/Equipment Building Name Building Type (See Section B.4)

ICS and other controls and communications equipment

Upgrader Operations Complex

Engineered building

Boiler feedwater treatment, air compressors, boiler auxiliary equipment; water treatment chemicals

Water Treatment Building Engineered building

ST/G and auxiliaries ST/G Building Engineered building High voltage electrical equipment (breaker controls, SCADA, protective relays, metering)

Substation Control Building Small, pre-manufactured building

Medium and low voltage switchgear and control centers, station battery, UPS, and similar electrical equipment

Electrical Building Pre-engineered building



Utility/Equipment Building Name Building Type (See Section B.4)

34.5 kV switchgear 34.5 kV Switchgear Enclosure

Pre-fabricated enclosure with switchgear factory installed

Raw water and fire suppression pumps and related equipment

Raw/Fire Water Pump Station Pre-engineered building

River water intake pumps and related equipment

River Water Intake Pump Station Pre-engineered building

Recycle water pumps Recycle Pump Station Pre-engineered building

IWT equipment; water treatment chemicals IWT Building Pre-engineered building

Sanitary forwarding pumps, basin, and related equipment

Sanitary Pumping Station Pre-engineered building

Diluted bitumen, diluent, and SCO pumps

Dilbit, Diluent, and SCO Pump Station

Small pre-engineered building in Tank Farm

Intermediate product pumps Intermediate Product Pump Station


Light ends unloading pumps Light Ends Pump Station


Flocculation, clarification and Ultrafiltration

Primary Water Treatment Bldg Small pre-engineered building

Stormwater pump equipment Stormwater Pump Building Small engineered building

These buildings will be equipped with lighting, heating/ventilating equipment, noise attenuation features, and similar facilities, and will be rated for environment and process hazards in accordance with the Alberta Fire Code.

B.5.9 Utilities Major Equipment List

A summary of major utilities equipment associated with balance-of-plant systems and the Project is included in Table B.5.9-1. The size and quantity of equipment are based on engineering completed to date, and is subject to change during detailed design.



Table B.5.9-1: Utilities Major Equipment

Equipment Approximate Size Per Unit

Number of Units or Trains

River water intake pump 2,160 m3/hr 3 Raw water pump 990 m3/hr 2 Recycle water pump 1,320 m3/h 3 Fire suppression pumps 1,022 m3/h 4 Boiler feedwater pre-treatment and treatment (RO/MBIX)

110 m3/h 3

Process cooling tower 8 to 12 cells IWT, with API oil/water separator n/a 1 Auxiliary steam boiler 90 tonnes/h 3 High Voltage Transformers 240 kV/138 kV Auto transformer 138 kV/ 34.5 kV Step-down transformer

200 MVA +/- 100 MVA +/-

2 6

Air compressor and dryer (per train) 5,000 m3/h 3 Product storage tank See Table B.5.8-1 21 Flares See Table B.5.8-2 3

B.6 Alternative Analysis

The NLP considered both alternatives to the Project and alternative means of undertaking the Project.

In terms of alternatives to the Project, there are no functionally different ways of carrying out the proposed Project. Further, the alternative of not proceeding with the Project was not considered viable, as the result would be a loss of the substantial benefits to be derived from the Project. The NLP also considered the implications of delaying the Project but decided to move forward with the current schedule in order to meet investor expectations and to secure access to increasingly scarce engineering fabrication and labour resources in a highly competitive marketplace.

In terms of alternative means of carrying out the Project, the NLP considered a number of alternatives for facility design and location during the pre-feasibility phase of Project development. The NLP’s decision-making approach considered, as applicable, a number of different factors including environmental, social, technical, operational and economic criteria.

As early as 2001, Synenco recognized that market conditions would not be favourable for bitumen prices and strongly supported the concept of full upgrading to produce a more marketable SCO product. If the supply of bitumen from Alberta’s oil sands



continued to rise as was forecast, the bitumen would need to be transported to increasingly distant refineries and would require large quantities of diluent for transportation. This would result in a lower netback and would lead to a wider price differential between bitumen and the alternative of upgrading into a light SCO. In addition, SCO supply of traditional quality was also rising at the time, which caused concerns of further price erosion. The NLP therefore targeted a higher quality SCO product that would capture a market premium relative to other synthetic crudes. This market assessment was a key driver in the final design of the Project.

The NLP evaluated several different Upgrader configurations that met the stated marketing and product objectives. The major process units comprising these configurations include:

delayed coking; fluid coking; hydrotreating; fixed bed hydrocracking; ebullated bed hydrocracking; steam methane reforming; SDA Unit; thermal cracking; gasification; and power generation.

Proposals were received from several different licensors and the various configurations (carbon rejection and hydrogen addition) were evaluated according to their ability to achieve the product objectives. The ultimate configuration was influenced not only by the desired premium quality target, but also by factors such as natural gas and electric power requirements and capital costs. Alternatives which were considered to be economic and technically feasibility were further assessed in terms of environmental and socio-economic effects.

The NLP determined that the optimal balance between capital and operating costs, the quality of the upgraded product and environmental and socio-economic considerations would be achieved by using a combination of processes including SDA Unit, fixed bed hydrocracking of the gas oil and deasphalted oil streams, and gasification of the asphaltenes to produce the hydrogen needed for hydroproccessing.

The following provides a comparison of the relative environmental and socio-economic advantages and disadvantages of selections made with respect to:



gasification vs. delayed coking (for asphaltene processing); gasification vs. steam methane reforming (for hydrogen production); and hydrogen sales vs. power generation (for use of excess hydrogen).

B.6.1 Gasification vs. Delayed Coking

Gasification and delayed coking were the two primary alternatives considered for processing of the SDA Unit asphaltenes. These were not necessarily mutually exclusive as it was initially envisaged that the asphaltenes produced from the SDA Unit in excess of the amount needed for hydrogen production in the gasifier would feed a delayed coker unit. However, factors weighing against this choice include the following.

The quantity of residue to the coker became too small to make the unit economic.

The decision to move the Project from the Northern Lights Mine and Extraction Project site to the Edmonton area also affected the technology selection process. The Edmonton location created a market opportunity to convert all the asphaltenes to syngas which could then be converted to either power or hydrogen and sold in the region.

The quality of coker liquid products is poor and requires hydroprocessing. There may be a performance risk associated with processing 100% asphaltene

feed to a coker unit. During public consultation, stakeholders and the community indicated a

preference that the Upgrader not employ coking technology.

From an environmental and socio-economic perspective, the NLP believes that gasification is a better alternative than delayed coking due to the following.

Increased use of bitumen energy content and corresponding reduction in natural gas and electric power consumption.

Gasification results in a relatively smaller volume of inert slag waste which may be suitable for other end uses such as road construction. This compares favourably to the challenges associated with petroleum coke waste from delayed coking. Not only is the energy content of the coke lost (unless used as a gasifier feed), but it has to be landfilled or stock-piled on-site which may have associated aesthetic issues and dust/particulate matter control challenges. Similarly, periodic decoking operations can lead to increased particulate matter emissions.

One aspect of gasification is the generation of high levels of greenhouse gas emissions (CO2). However, the NLP will mitigate this by creating a high purity CO2 stream which



will be suitable for other end uses such as urea production (as contemplated in the Agrium MOU) or enhanced oil recovery. Further, the NLP will explore economically feasible options for the capture and storage of process CO2 emissions from the gasifier for which no productive end use can be found. Consequently, the NLP selected gasification as the preferred alternative.

B.6.2 Gasification vs. Steam Methane Reforming

Gasification and steam methane reforming (SMR) were the two alternatives considered for hydrogen production.

From an environmental and socio-economic perspective, SMR may produce lower airborne emissions but consumes large quantities of natural gas for feed and fuel.

The selection of gasification proved to be the most economic alternative and reduced the Project’s dependency on natural gas to produce the hydrogen needed for hydroproccessing. Gasification consumes a low value upgrading by-product and produces a high value hydrogen product whereas SMR uses natural gas as feed for producing hydrogen. SMR uses marginally more water than gasification, however, gasification uses substantially more power than SMR due to the need for pure oxygen from the ASU.

B.6.3 Hydrogen Sales vs. Cogeneration

The NLP considered two alternative configurations to make efficient use of by-product asphaltenes from the upgrading process, using gasification technology.

One gasifier configuration maximizes syngas production, providing excess syngas which could be used to power combustion turbines and support steam/electricity cogeneration. The resulting steam and electricity would principally be used on site, with excess electricity available for sale to the Alberta Power Pool (termed the “Power Generation” case); and

Another gasifier configuration maximizes hydrogen production for direct sale to local industries (termed the “Maximum Hydrogen Generation” case). This configuration results in limited on-site power generation and, as a result, requires power purchase from the Alberta Power Pool.

The “Power Generation” case was initially the base case for the gasifier configuration and preliminary engineering was completed for this alternative and the resulting cogeneration plant. However, following the signing of the MOU to provide excess hydrogen and various other Upgrader by-products to Agrium, the NLP decided to re-configure the gasifier with a shift converter to maximize hydrogen production. This


Part B October 10, 2006 Page 94

alternative was ultimately selected based on better overall economics and reduced air emissions, as the cogeneration plant would have produced fairly high NOx, CO, and CO2 emissions through syngas combustion. The current and projected overcapacity of power generation in this area of the Province further supported the NLP’s decision to purchase power and maximize hydrogen production.

The Maximum Hydrogen Generation case will consume more water than the Power Generation case as water is consumed in the reaction to produce hydrogen. From an environmental and socio-economic perspective, the NLP considers the Maximum Hydrogen Generation case to be preferable as it results in decreased air emissions and noise.

A comparision of key air quality parameters indicates a reduction in emissions for the Maximum Hydrogen Generation case compared to the Power Generation case as shown in Table B.6.3-1. The NLP acknowledges that the Maximum Hydrogen Generation case requires the purchase of power which would not be necessary under the Power Generation case. The ‘indirect’ emissions associated with third-party power generation are only considered in terms of greenhouse gas emissions (see section B.8). The key air quality parameters compared below reflect direct emissions from the facility which is appropriate given that these emissions are of concern with respect to the airshed. It should also be noted that selling excess hydrogen to industrial partners (such as contemplated under the MOU with Agrium) would significantly reduce their natural gas consumption and result in a corresponding decrease in emissions.

Table B.6.3-1 Comparison of Key Air Quality Parameters – Power Generation vs. Maximum Hydrogen Generation

Parameter Power Generation Case (t/d)

Maximum Hydrogen Generation Case (t/d)

Sulphur Dioxide 31.08 28.85 Nitrogen Oxides 9.39 3.11 Carbon Monoxide 9.57 4.56 Particulate Matter 0.43 0.21

Further, initial results from the Human Health Risk Assessment predicted that polyaromatic hydrocarbon (PAH) emissions from the Power Generation case would act cumulatively with future PAH emissions from other proposed facilities in the region to create potentially significant health risks at a number of discrete receptor locations. The decision to move to the Maximum Hydrogen Generation case effectively eliminates this human health risk.



B.7 Air Emission Management

Air emissions from the Project are associated with a number of sources, including:

point sources from the Upgrader facilities; fugitive emission sources; and vehicular traffic supporting the Project.

This section describes how the NLP will manage air emissions and related issues throughout the life of the Project. Project emissions are addressed in Volume 2, Section E.1 and Volume 3, CR#1 Air Quality.

B.7.1 Sulphur Dioxide

Project-related SO2 emissions are associated with the sulphur recovery operations and the combustion of fuels containing sulphur in process equipment and vehicles. Flaring events can also be a source of SO2. Additional details regarding SO2 emission quantities and calculation methods can be found in Volume 2, Section E.1 Air Quality.

To manage SO2 emissions from the Project, the NLP will employ the following operational standards and procedures:

use of catalytic train technology to ensure that sulphur recovery efficiency will be at least 98.8% and will meet EUB requirements;

purchased natural gas or cleaned fuel gas, containing nearly no sulphur, will be used as fuel;

fuel gas will be mainly PSA tail gas which will be cleaned in the gasifier scrubbing and H2S removal column;

use of low sulphur diesel in diesel-powered vehicles consistent with federal regulations governing sulphur levels in diesel fuel; and

no continuous flaring except for pilot gas and the flare purge gas that is required for safe operation of the flare system. Flare purge will typically be nitrogen, which is available as a by-product of the ASU and more environmentally friendly, safer, and lower cost than natural gas.

B.7.2 Nitrogen Oxides

Project-related NOX emissions are associated with all combustion processes and emissions from vehicles. Additional details regarding NOX emission quantities and calculation methods can be found in Volume 2, Section E.1.



To manage NOX emissions from the Project, the NLP will employ the following operational standards and procedures:

the selection of low-NOX emissions technology such as low-NOX burners in auxiliary boilers as required by the CCME National Emission Guideline for Commercial/Industrial Boilers and Heaters;

promoting the use of bus transportation for employees and contractors to reduce vehicle traffic; and

capture and use of syngas produced in the Upgrader as opposed to direct discharge to the environment.

B.7.3 Volatile Organic Compounds

Project-related VOC emissions are associated with combustion equipment and fugitive emissions from the Project. Additional details regarding VOC emission quantities and calculation methods can be found in Volume 2, Section E.1.

To manage VOC emissions from the Project, the NLP will employ the following operational standards and procedures:

plant-wide fugitive emissions identification and control using the protocol recommended by the CCME guideline “Environmental Code of Practice for the Measurement and Control of Fugitive Emissions from Equipment Leaks”;

storage tanks will conform to the CCME guideline “Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from Above Ground Storage Tanks”;

vapour recovery systems on tanks, where required, to reduce the emissions of VOCs;

nitrogen blanketing on diluted bitumen tanks to minimize emissions; floating roofs on tanks where product degradation or vapourization could occur

due to vapour pressures higher than atmospheric; double mechanical seals, where appropriate, on pumps in high vapour pressure

liquid service; covers on API separators to minimize emissions and odours from hydrocarbon

products in the feed stream; and use of paraffinic solvents rather than the more volatile, and higher aromatic

compounds, naphthanic counterparts as diluent.



B.7.4 Particulate Matter

Project-related PM emissions are associated with combustion sources, vehicle emissions and fugitive dust from traffic on roadways. Additional details regarding PM emission quantities and calculation methods can be found in Volume 2, Section E.1.

To manage PM emissions from the Project, the NLP will employ the following operational standards and procedures:

during construction, the NLP will minimize slash burning; during all phases, the NLP will apply dust suppressants, including water, during

dry periods to reduce fugitive dust; and routine maintenance will serve to reduce PM emissions from vehicles.

B.7.5 Odours

Odours are attributed to a number of VOCs and reduced sulphur compounds. Odourous emissions can be emitted from incomplete combustion of fuels as well as fugitive emissions from the Project and storage tanks. Biogenic sources of odour, usually in the form of total reduced sulphur compounds, include swamps, bogs and lakes.

To manage odourous emissions from the Project, the NLP will employ the following operational standards and procedures:

control of VOC emissions and fugitive emissions, as stated above; combustion/conversion of H2S in emission streams to SO2; and rigorous equipment maintenance and replacement procedures.

B.7.6 Visible Emissions

Visibility and visual aesthetics may be affected by plume presence. Visible plumes may be associated with combustion processes, flare stacks and water vapour plume from cooling towers.

To manage visible emissions from the Project, the NLP will employ the following operational standards and procedures:

each emergency flare system will include liquid knockout facilities, flame ignition and burner management with steam injection to reduce visible emissions; and

emissions reduction measures described above will also serve to reduce the effect on visibility and visual aesthetics.



B.7.7 Air Quality Monitoring

The NLP will conduct emissions tests for NOX on all major boilers. The sulphur recovery stack will be equipped with a CEMS to measure SO2, as well as sampling ports for compliance stack emissions testing.

Synenco is a member of the Northeast Capital Industrial Association (NCIA) regional air quality management initiatives and will maintain an active role as appropriate for its operation. The most significant regional initiative that affects the management of air quality in the region is the Fort Air Partnership (FAP). FAP operates an ambient air quality monitoring network of eight continuous monitoring stations and thirty passive monitoring stations. The NLP will contribute to regional monitoring through support of the FAP air monitoring program.

The NLP will work with AENV to determine if additional ambient monitoring is required for the Project. Air quality monitoring results will inform future air quality management, as mandated by the NLP’s commitment to an adaptive management approach.

B.8 Greenhouse Gas Emissions and Climate Change

B.8.1 Introduction

This section provides an assessment of greenhouse gas (GHG) emissions from the Project and addresses potential impacts of climate change on the Project. Aspects of the Project’s design that will minimize GHG emissions are described in the following GHG Management Strategy that will incorporate a process of continuous improvement throughout the life of the Project. Expected GHG emissions over the construction, operation and decommissioning phases of the Project are presented and the marginal contributions to total provincial and national GHG emissions are calculated. A Project GHG intensity number per unit of bitumen processed is calculated and compared to other similar projects.

A GHG is any gas that contributes to potential climate change. Common GHGs include carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). GHGs absorb heat radiated by the earth and subsequently warm the atmosphere, leading to what is commonly known as the greenhouse effect.

B.8.2 Greenhouse Gas Management Strategy

Synenco will meet or better the regulatory requirements of the Province of Alberta in terms of GHG emissions reporting and control. Alberta has adopted climate change legislation that provides the Province equivalency with the federal government’s Canadian Environmental Protection Act (CEPA). Compliance with Alberta legislation



thus ensures compliance with the CEPA. Synenco recognizes the importance of this issue and anticipates additional policy and regulatory changes in the future.

Further, Synenco recognizes that large final emitters must continue dialogue with federal and provincial governments with a view to continuous improvement. GHG emissions are assessed in terms of the technologies to be used and in the management decisions taken in construction, operation and decommissioning of the Project. Best practice will be the standard for the construction phase of the Project. Reduction of GHG emissions will be incorporated into the Project design. These approaches will be particularly important to help minimize GHG emissions during the operational phase of the Project.

The following GHG mitigation measures will be adopted.

The Project will be designed to produce a high purity process CO2 stream from the gasifier that will be suitable for various end uses such as enhanced oil recovery via CO2 miscible flooding and fertilizer production. The NLP will continue to pursue/develop other end use market opportunities for the CO2 by-product. Further, the NLP will explore economically feasible options for the capture and storage of CO2 volumes for which no productive end use can be found.

Optimization of energy efficiency during Project design and operations. Use of high efficiency equipment and minimization of leaks and fugitive

emissions through use of tank vapour control systems, gaskets and seals and monitoring programs.

Equipment purchasing decisions in the future will be made with consideration of continuous improvement principles, energy efficiency and appropriate equipment sizing.

Rigorous equipment maintenance and replacement procedures. Implementation of a GHG monitoring and reporting program to measure and

identify energy use trends and GHG reduction opportunities. Training programs for operations personnel with a focus on reviewing plant

energy use trends and identifying opportunities for improvement. Establishment of continuous improvement targets for the reduction of GHG

emissions as part of the business planning cycle.



B.8.2.1 Project GHG Emissions

The Project will have emissions of GHGs in the form of:

direct emissions from combustion sources (equipment burning fuel resulting in CO2 and N2O emissions);

direct emissions from the process (CO2 produced in the gasification process); fugitive emissions (in particular CH4) from the plant; and indirect emissions from electricity purchased (produced at a power plant).

Since N2O and CH4 have a higher greenhouse warming effect than CO2, they are typically expressed in terms of equivalent amounts of CO2, or CO2 equivalents (CO2e). N2O and CH4 have a global warming potential that are 310 and 21 times that of CO2, respectively. Estimates of greenhouse gas emissions from the Project were calculated using United States Environmental Protection Agency (US EPA) emission factors.

Expected GHG emissions for the construction, operational and decommissioning phases of the Project are presented in Tables B.8.2.1-1, B.8.2.1-2 and B.8.2.1-3, respectively.

Table B.8.2.1-1: Expected GHG Emissions for Construction Phase

Source Fuel Quantity(1) Emission Factor(2) CO2e (t/yr)

Light Trucks Gasoline 4,840 m3/y 2.34 t/m3 11,325 Cranes Diesel 620 m3/y 2.71 t/m3 1,680 Earth Movers Diesel 890 m3/y 2.71 t/m3 2,412 Welders Diesel 3,460 m3/y 2.71 t/m3 9,377 Lighting Gasoline 1,100 m3/y 2.34 t/m3 2,574

Heaters Propane/Natural Gas 21,900 m3/y 1.50 t/m3 32,850

Indirect emissions (Purchased Electricity 30 MW) Power Grid 262.8 GWh 631.9 t/GWh 166,063

Total GHG Emissions - - - 226,281 (1) Estimate from industry experience. (2) US EPA emission factor.



Table B.8.2.1-2: Expected GHG Emissions for Operations Phase

Source CO2 (t/d) CH4 (t/d) N2O (t/d) CO2e (t/d) CO2e (t/y) Atmospheric Tower Heater 600.7 0.012 0.010 604.18 220526 Vacuum Heater 248.1 0.005 0.004 249.50 91068 SDA Heaters 671.9 0.013 0.012 675.82 246674 DAO Feed Heater 46.0 0.001 0.001 46.26 16885 AGO Feed Heater 47.3 0.001 0.001 47.56 17359 VGO Recycle Gas Heater 36.8 0.001 0.001 37.02 13512 DAO Feed Heater 46.0 0.001 0.001 46.26 16885 AGO Gas Heater 47.3 0.001 0.001 47.56 17359 VGO Recycle Gas Heater 36.8 0.001 0.001 37.02 13512 Auxiliary Boiler #1 666.4 0.013 0.012 666.4 243236 Auxiliary Boiler #2 666.4 0.013 0.012 666.4 243236 Auxiliary Boiler #3 666.4 0.013 0.012 666.4 243236 Sulphur Stack 1087.8 0.004 0.004 1,089.05 397503 Gasification 11,100.0 0.0 0.0 11,100.0 4051500 Total Emitted* 15,967.9 0.078 0.071 15,991.40 5,836,861 Indirect emissions (Purchased Electricity 261.1 MW)

- - - 3,959.74 1,445,304.4

Total Emitted and Indirect* - - - 19.939.32 7,282,165.4 * Totals subject to rounding differences

Table B.8.2.1-3: Expected GHG Emissions for Decommissioning Phase

Source Fuel Quantity(1) Emission Factor(2) CO2e (t/yr)

Light Trucks Gasoline 795.8 m3/y 2.34 t/m3 1862.2 Cranes/Wrecking Machines/Backhoes Diesel 298.4 m3/y 2.71 t/m3 808.7

Earth Movers Diesel 663.2 m3/y 2.71 t/m3 1,797.3 Plasma Cutters Diesel 566.4 m3/y 2.71 t/m3 1,534.9

Heaters Propane/Natural Gas 5,500 m3/y 1.50 t/m3 8,250.0

Indirect emissions (Purchased Electricity 15 MW) Power Grid 131.4 GWh 631.9 t/GWh 83,032

Total GHG Emissions - - - 97,285.1 (1) Estimate from industry experience (2) US EPA emission factor

Estimated total GHG emissions for the life of the Project are presented in Table B.8.2.1-4. The Project’s marginal contributions to the total provincial and national GHG emissions are shown in Table 8.2.1-5. Both tables conservatively assume that all CO2 emissions associated with the Project are released to the atmosphere.



Table B.8.2.1-4: Expected Total Greenhouse Gas Emissions Years Annual GHG (t/yr) Total GHG (tonnes)

Construction 2 226,281 452,562 Operations 30 7,282,165 218,464,950 Decommissioning 2 97,285 194,570 Total Emissions - - 219,112,082

Table B.8.2.1-5: Project Contribution to Total Provincial and National GHG Emissions

Canada(1) Alberta(1) Northern Lights Total Percentage Total Percentage

CO2e (Mt/y) CO2e (Mt/y) (%) CO2e (Mt/y) (%) Greenhouse Gas Emissions

7.28 731 1.00 221 3.29

(1) Canada’s Greenhouse Gas Inventory for 2002, Environment Canada (2004)

The intensity of GHG emissions per unit of bitumen processed is presented in Table B.8.2.1-6. Three GHG intensity numbers are provided for comparison purposes.

The first GHG intensity number is based on the direct emissions from the Project (i.e., from on-site emission sources) and is calculated at 159.9 kg of CO2e per barrel of production.

The second GHG intensity number represents direct emissions plus indirect emissions (i.e., emissions that are created elsewhere in the generation of the electricity sold to the Project) and is calculated to be 199.5 kg of CO2e per barrel of production.

The third GHG intensity number represents the direct and indirect emissions of the Project with full gasifier process CO2 capture and is calculated to be 88.5 kg of CO2e per barrel of production, a 55% reduction from the full CO2 venting case.

GHG intensity numbers from other projects are also presented in Table B.8.2.1-6.

It is important to note that GHG intensity numbers between projects may not be directly comparable given different process designs and/or feedstock and product slates. For example, projects may or may not include gasification, co-generation and hydrogen production processes. Also, emission estimates may be based on different calculation methodologies.

Further, the emissions do not necessarily represent life-cycle emissions. For example, the NLP Upgrader will produce excess hydrogen for sale to other users which will substantially reduce the GHG emissions of the purchasing facility as they no longer



require energy to produce their own hydrogen (typically through SMR). These third-party reductions are not reflected in the Project GHG numbers presented in this Application.

Table B.8.2.1-6: Comparison of GHG Emissions with Other Upgrader Projects

Product (bpd)

GHG Emissions (t/d)

GHG Intensity (kg/bbl)

Northern Lights (direct emissions)

100,000 15,991 159.9

Northern Lights (direct emissions + indirect)

100,000 19,951 199.5

Northern Lights (with CO2 capture)

100,000 8,851 88.5

Others: BA Energy - Heartland 260,400 3,645 14 Husky - Lloydminster 60,000 3,937 65.6 North West Upgrader 150,000 13,922 92.8 Opti/Nexen – Long Lake 140,000 25,200 - 30,800 180 – 220 Shell – Scotford 290,000 9,540 32.9 Suncor 542,000 58,940 108.7 Syncrude 250,000 26,500 106

B.8.3 Climate Change

Climate change is of interest because of the potential effects it may have on sensitive stages or elements of the Project. Changes in climatic conditions (temperature, precipitation and wind) may affect Project construction (delays due to inclement weather), operations (energy use, water supply, air dispersion and other environmental components) and decommissioning and reclamation activities (efforts to restore the land to its previous use). These effects are assessed to help recognize potential requirements needed to adapt the Project from time to time over its anticipated life and to ensure that any potential adverse effects are minimized and managed such that they do not pose a risk to the public or the environment.

Climate change is the change in the Earth’s global climate, or regional climates, over time. These changes may result from processes within the Earth, external forces (such as the sun) and more recently, human activities (such as burning of fossil fuel, deforestation and intensive livestock operations). Climate change factors which can influence climate, called climate forcings, include processes such solar radiation and GHG concentrations.

An increase in the mean global temperature (global warming), altered precipitation patterns and amounts (extreme weather events), retreating glaciers and rising sea levels are being observed. There are, however, skeptics who argue the climate is not



changing, or that the global climate is getting warmer, in part because of human activity, but that this will create more benefits than costs (such as more agricultural area), that the impacts are not sufficient to require any policy response or that the cost to take action is too high. The United Nations Framework Convention on Climate Change (UNFCCC) acknowledges a lack of full scientific certainty about some aspects of climate change but also state that it is not a reason for delaying an immediate response that will, at a reasonable cost, prevent dangerous consequences in the climate system.

To consider climate change impacts, global climate models (GCMs) and regional climate models are used to predict possible future climate scenarios. Some complex GCMs take into consideration interactions between the atmosphere, ocean, sea ice and land, atmospheric chemistry, carbon cycles and future GHG emissions. However, these models are limited by many factors such as a large number of meteorological variables, large spatial and temporal scales and many possible future global emissions scenarios.

Barrow and Yu (2005) presented some possible climate scenarios in their report “Climate Scenarios For Alberta (Prairie Adaptation Research Collaborative, May 2005)”. They looked at various global climate model projections and examine how these predictions may translate to situations in Alberta. Table B.8.3-1 presents climate scenarios, including a median scenario that may be representative of conditions in the 2050s (period from year 2040 to year 2069).



Table B.8.3-1: Climate Change Scenarios for Edmonton 2050s (2040-2069) Global Climate Model (GCM)

Baseline CGCM2 CCSRNIES NCAR-PCM HadCM3 HadCM3

Difference between

Baseline and Median

Emissions Scenario B2 (3) A1FI A1B A2 (a) B2 (b)

Scenario Type Cooler,

drier Warmer,

drier Cooler, wetter

Warmer, wetter Median

30-Year Period 1961-1990 2050s 2050s 2050s 2050s 2050s

Annual Mean Temperature (°C)

2.5 5.1 6.9 4.7 4.5 5.0 +2.5

Annual Precipitation (mm)

457.8 481.5 494.1 498.6 482.0 479.2 +4.7%

Growing Degree Days Index (DD5)*

1445.7 1852.4 2030.6 2009.8 2154.4 2076.3 +44%

Annual Moisture Index (AMI)**

3.2 3.8 4.0 3.9 4.4 4.5 +41%

Source: Climate Scenarios for Alberta, Prairie Adaptation Research Collaborative, Barrow & Yu, May 2005 *Degree Days greater than 5°C (DD5) is an indicator of the warmth of the growing season for general plant growth, i.e., lengthening of growing season and/or the availability of more heat units for plant growth. It is calculated by summing the difference between daily mean temperature and 5°C, on days when the mean temperature exceeds 5°C. **Annual Moisture Index (AMI) is the ratio of DD5 to mean annual precipitation. It combines temperature and precipitation to give an indication of moisture availability for plant growth. An increase in AMI indicates increased moisture stress (less precipitation available to support enhanced plant growth). (1) Center for Climate System Research/National Institute for Environmental Studies (2) National Centre for Atmospheric Research – Parallel Climate Model (3) Coupled Global Climate Model (4) Hadley Center Coupled Model 3

B.8.3.1 Effects on the Project

The sensitivity of the Project to the effects of climate change was assessed by qualitative means using the projections of the median case. The median case predicts that annual mean temperature and annual precipitation will increase by 2.5°C and 4.7% (457.8 mm to 479.2 mm) for the 2050s, respectively. Although warmth may increase plant growth, less moisture is available to support the enhanced plant growth.

For the construction phase of the Project, extreme weather conditions may affect the delivery of material and construction activities. However, the magnitude of the predicted impact will be low and duration of the construction phase will be short). The residual effect of climate change is expected to be not significant.

For the operational phase, the following sensitivities of the Project to climate change are assessed.



Plant operation due to direct temperature change – no impact on the plant as it is designed for operation between 40°C and minus 45°C.

Water management ponds due to direct precipitation change – surface runoff ponds may need to be larger to handle peak rain events. However, increased temperature will also increase evaporation rate out of the ponds.

Water withdrawal from the NSR for project use – no changes in water use are anticipated as a result of climate change. However, increased rainfall, temperature and evaporation may, or may not, affect the river water levels as the NSR is a managed river (controlled upstream by dams).

Surface water predictions due to climate change – warmer temperatures may increase water temperature and may increase evaporation. Water levels and flows in lakes and rivers may decrease due to evaporation and may increase due to snow and glacier melt. A reduction in levels and flows may increase in-stream concentrations. These changes are expected to be low in magnitude.

Groundwater predictions due to climate change – groundwater systems are buffered from direct climate changes but may have an effect on the rate of recharge on groundwater system. However, groundwater systems are usually large in volume and the rate of movement is slow, therefore climate change impacts to groundwater are expected to be not significant.

Ambient air quality predictions due to climate conditions – plant emissions have been modeled for various meteorological conditions, including various wind conditions. Changes to air quality predictions due to temperature and wind conditions are expected to be low in magnitude. Increased rainfall may increase acid (wet) deposition near the project and as a consequence, dry deposition would decrease near the plant.

For the decommissioning phase of the Project, climate change may affect reclamation and revegetation activities. These effects are anticipated to be low in magnitude. However, various species mix, reclamation techniques and adaptive management approaches that are successful under a wide range of climatic conditions will be used, depending upon climate conditions at that time. Appropriate monitoring programs will be implemented to measure reclamation success. Given the relative small size of the Project, it is expected that any adaptive measures that are foreseeable will be easily incorporated into the Project’s plans.

Overall, the predicted change in climate will have no significant effect on the Project. Prediction confidence is very high based on quality of baseline data, confidence in analytical techniques, and confidence in the numerous mitigation practices and technologies.



B.9 Waste and Chemical Management

This section outlines the waste streams generated by the Project and the chemical product consumption of the Project, as well as describing the various storage and disposal methods that will be used in managing waste and chemicals.

B.9.1 Waste Management Overview

As part of its comprehensive Health, Safety and Environmental (HSE) Management System, Synenco will develop a waste management plan for the Project to ensure safe and proper handling of wastes. This plan will include the following components:

details on appropriate awareness and training programs; personnel roles and responsibilities; contingency plans; contractor management; performance measurement; and verification measures and monitoring.

The implementation of a waste management plan will allow the NLP to appropriately document, track and report on their waste management practices, and identify opportunities for continuous improvement of waste management practices.

The overall waste management plan, including the design of waste management facilities, is based on the following assumptions for the Project:

the waste management strategy will cover all on-site generated wastes (both hazardous and non-hazardous);

waste management facilities will be sited and constructed to meet regulatory requirements;

where possible and when appropriate, generated waste will be directed to recycling;

waste minimization programs will be implemented to reduce quantities of waste produced;

waste disposal shall be conducted on-site (except for those wastes requiring specialized disposal or recycling); and

the waste management plan will be guided by a number of principles that help to ensure that all materials will be used in the most efficient way possible and that the quantities of waste generated are kept to a minimum as reasonably practicable.



The waste management plan will reflect a waste management hierarchy which places emphasis on waste minimization techniques, followed by the responsible disposal of wastes that are generated.

Pollution prevention and recycling programs and waste storage, disposal and minimization activities and are discussed in Section B.9.

B.9.2 Waste Streams

Waste streams will be produced from a variety of sources during the construction and operation of the Project including, but not limited to:

construction activities (such as building construction, clearing and brushing); process operations; administration facilities (such as typical office waste materials); maintenance activities (such as vehicle and heavy equipment routine and non-

routine maintenance and repairs); and laboratory facilities.

A list of wastes that will or may be produced during the life of the Project, estimated waste quantities, and waste disposition are presented in Table B.9.2-1.

Table B.9.2-1: Waste Management Summary

Waste Description

Source and Estimated Amount

Generated

Storage Method and

Location Disposal Method and

Location

Liquids Surface run-off water (developed area)

Developed area stormwater runoff,

at flows up to 36,000 m3/d (1 in 100 year return

event)

Sent through oil/grit separator and stored in stormwater pond

Reused/recycled in the process

Surface run-off water (non-developed area)

Undeveloped area stormwater runoff

at flows up to 12,000 m3/d (1 in 100 year return

event)

Via natural flow paths to existing watersheds (flows to NSR will pass through sediment pond)

Clean stormwater sent to current watersheds, including the NSR



Waste Description


Generated

Storage Method and


Location

Boiler blowdown water 2 m3/day Quenched boiler blowdown forwarded to IWT plant to be treated and reused via the recycle water pond


Cooling water blowdown 120 m3/hr Sent via collection tank to RO unit for processing, with recovered permeate returned to tower basin (recycled)

Blowdown RO rejection sent to deep well injection

Steam condensate Approximately 70 percent of steam generated on-site

recovered and reused

Processed via condensate polisher and sent to Deaerators.

Reused/recycled in the process.

MBIX waste 3 m3/hr Sent via collection tank to RO unit for processing, with recovered permeate returned to cooling tower basin

Blowdown RO rejection sent to deep well injection

Feedwater RO reject stream

56 m3/hr Sent via collection tank to IWT plant to be treated and reused, via the recycle pond


Condensate polisher 9 m3/hr Sent via collection tank to IWT plant to be treated and reused, via recycle pond.


Vessel drains Intermittent. Sumps. Reused/recycled in the process

Produced water Never encountered. N/A N/A

Floor wash (service water)

Intermittent, 4 m3/d To floor drains, with discharge to IWT plant to be treated and reused via recycle pond


Equipment wash (service water)

Intermittent, 25 m3/yr

To drains, with discharge to IWT plant to be treated and reused via recycle pond


Vent/ flare liquids Intermittent Flare knockout drums, sent to IWT plant via API separator




Waste Description


Generated

Storage Method and


Location

Filter backwash (Primary Water Treatment Building)

32 m3/hr (ultrafiltration backwash)

Internally returned to Flocculation treatment

Reused/recycled in the process, with sludge from Flocculation/Settling sent to landfill (see “Sludge” below)

Recycle Pond Blowdown Pond volume (estimated less than

twice per year)

Pond contents Forwarded to deep wells for disposal

B.9.3 Waste Minimization

Minimizing Project waste includes prevention of waste generation and recycling of those wastes which are produced. The primary benefits of waste minimization are reduced costs, both to the environment and proponent, of waste handling and disposal. The anticipated benefits of waste minimization include:

reduced waste handling, disposal or recycling costs; reduced operating costs; reduced costs associated with inefficient or wasteful use of material or energy

inputs; reduced on-site storage costs; reduced transportation costs for waste; reduced health hazards to employees or other stakeholders; reduced risks and environmental management costs associated with ensuring

compliance with waste control regulations; and enhanced reputation for responsible corporate practices.

Waste minimization activities will be ongoing. As new processes, materials, or management practices are adopted at the Project site, they will be subject to a waste management review to identify opportunities for waste minimization.

A Project Waste Manager will be responsible to oversee waste minimization efforts, make recommendations regarding waste minimization to the NLP corporate management and engineering teams, and liaise with employees to identify opportunities for reducing the volume, toxicity and environmental burden of waste. Additionally, the Project Waste Manager will assess and incorporate, as appropriate, evolving industry best practices, industrial ecology or cleaner production technologies that are feasible, cost-effective and relevant.



Waste minimization practices will be integrated into business activities for Project operations. For example, some areas in which an integrated approach will be reflected include:

corporate planning for, and tracking of waste management and minimization achievements, development of waste reduction indicators, and placing accountability on individual departments to contribute to the program;

training programs for new employees and ongoing staff awareness programs; and

annual review of programs as part of the annual review process.

The Project’s HSE Management System, which is discussed in detail in Section B.10, will be the means by which waste minimization practices are integrated. Components of the HSE Management System which are relevant include goal and objective setting, worker competence and training initiatives, performance measurement, auditing and inspection.

B.9.3.1 Pollution Prevention

Pollution prevention is specifically targeted at avoiding the generation of waste to the greatest extent possible. More specifically, it involves ”using processes, practices, materials, products or energy that avoid or minimize the creation of pollutants and waste or environmental disturbance, and reduce risk to human health or the environment” (AENV 2005).

Pollution prevention will be accomplished by a recurring review of Project processes, material and energy inputs, maintenance procedures, purchasing practices, and staff support activities in an attempt to achieve improved performance. Additionally, specialists in industrial ecology or clean technology and production may be periodically consulted to ensure that all opportunities for pollution prevention are identified.

The Project Environmental Manager will develop a pollution prevention program. This program will be established and be in effect prior to commencement of Project construction and will help to prevent, reduce or reuse Project wastes.

B.9.3.2 Recycling Program

There exist numerous opportunities for the recycling of wastes from the Project which is preferred over waste disposal by landfilling.

The overall decision to recycle a particular waste will be based on several factors:

availability and accessibility of facilities for recycling;



regulatory requirements for disposal methods, particularly with respect to hazardous wastes;

availability of third party contractors to transport recyclables; quantities of waste generated on-site (a factor of the success of pollution

prevention programs); considerations of product/waste life cycle perspectives; and overall environmental costs associated with recycling.

For non-hazardous recyclable materials, it is anticipated that paper, cardboard and milk jug-type plastics will be collected for recycling. As appropriate, other commodities will be evaluated for recycling as viable markets develop and recycling facilities become available.

Many of the hazardous wastes generated are recyclable and will require off-site services for processing. Specialized contractors will be engaged to collect these wastes from the Project site and transport them to recycling and processing stations. The NLP will require that all contractors maintain full compliance with applicable regulations pertaining to the transportation of dangerous goods and processing.

The Waste Manager will be responsible to ensure that all recycling activities are carried out in a manner that reflects current best practices for waste management and recycling.

B.9.4 Waste Storage and Disposal

B.9.4.1 Waste Streams

Wastes will be stored in approved facilities/containers as described in Table B.9.2-1 prior to disposal. These storage facilities will use secondary containment as necessary and will be clearly marked for proper identification. Waste storage facilities will include a hazardous waste storage building, recycling depositories, laboratory waste bins, tanks for liquid wastes and segregation areas for general wastes such as batteries and aerosol cans.

B.9.4.2 Hazardous Waste Storage

Hazardous wastes and recyclables generated at the plant site will be disposed or recycled off site at approved facilities. These wastes include: waste oils; solvents; carbon from filters; used rags and absorbents; certain filters, media, and catalysts; surplus process and water treatment chemicals; batteries; aerosol cans; paint waste; laboratory wastes; and contaminated soil, debris and absorbents (if they are determined to be hazardous). The estimated volumes and preliminary disposal options are outlined in Section B.9. A hazardous waste storage facility will be constructed for storage of



hazardous wastes and recyclables prior to shipping to the disposal facilities. Hazardous recyclable wastes will be stored at the storage facility, bulked into larger secure containers and shipped to licenced recycling facilities specializing in the particular wastes to be managed. The location of the hazardous waste storage facility is shown on Figure B.4.1-1.

The hazardous waste storage facility will be designed to meet the requirements found in “Hazardous Waste Storage Guidelines” published by Alberta Environment in June 1988 and amended. The facility will be designed to contain leaks and to isolate incompatible materials from one another. Requirements of the Guidelines include:

the facility will be readily accessible for fire-fighting; the site will not be subject to flooding; the site will be equipped with fire-fighting equipment to comply with the Alberta

Fire Code; access will be limited to employees who have been trained in the management of

wastes that will be produced by the NLP; signs will indicate that hazardous waste is stored therein; the floor will be coated with an impermeable barrier which will not react with or

absorb the wastes being stored in the building; the floor will not have any drains that connect to a sewer; a continuous impervious curb (minimum height of 15 cm) will be placed around

each storage area; the storage area will have a roof and sidewalls to protect the waste from the

weather; if tanks are needed, the requirements of the Standards for waste storage tanks

will be observed; emergency equipment including overpack drums will be available to manage any

spills or leaks; and wastes will be adequately labeled.

The storage facility will be constructed near the maintenance shop. The size will be approximately 900 m2. It will be constructed with adequate ventilation and will be serviced by power. The design of the hazardous materials and waste storage facility is shown on Figure B.9.4.2-1.

B.9.5 Chemical Management

Chemicals used for the Project will be delivered to the site in containers and using means that comply with applicable regulatory requirements. On-site chemical storage



will be in compliance with Synenco’s HSE Management System and applicable standards and regulatory requirements. Chemicals will be moved to the applicable process areas as they are required.

All chemicals will be managed according to applicable legislation and requirements of the Workplace Hazardous Materials Information System (WHMIS). Material Safety Data Sheets (MSDS) for all chemicals will be available on-site in a convenient marked location.

A list of chemical products that will likely be used during Project construction and operation is presented in Table B.9.5-1.

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Table B.9.5-1: Chemical Product Consumption

Chemical Purpose Storage CEPA Substance

Classification (Schedule 1, PSL2, NPRI, Track 1)

AGR solvent Acid gas clean-up Surplus stored in a tank

AGR solvent

Alum Chemical precipitation Double-walled containers

Ammonium hydroxide solution (ammonia)

Boiler feedwater to control pH. Corrosion protection in the Atmospheric and Vacuum column overheads.

Mixing or solution tanks, with containment berms

Antifoam Used in cooling tower, amine system and AGR unit in gasifier

Mixing tanks, totes or solution tank(s), with containment berms

Schedule 1, PSL2, NPRI

Anti-scalant Cooling tower and RO to prevent scaling


Schedule 1

Biocide Cooling water system for microbio upsets and in the UF/RO system for cleaning membranes.


Carbon dioxide treatment hydrolysis catalyst

Carbon dioxide treatment

Typically on-time delivery for use. Provided in bins or large bags. Used in process vessels

Carbon dioxide treatment zinc oxide absorbent

Carbon dioxide treatment

Typically on-time delivery for use. Provided in bins or large bags Used in process vessels

Caustic (or geosol) MBIX regeneration and boiler water pH control.


Chlorine (or sodium hypochlorite)

Cooling tower to control biological growth and upstream of UF/RO in the raw water system to control bio growth.


Citriclean Used for cleaning of equipment (washing)

Drums or pails

Coagulant Used in the removal of fine sediment in the raw water


Monodiethanolamine (MDEA)

Acid gas clean-up Surplus stored in a tank with containment berms

Dispersant Used in boiler water Stored in tote tanks.





treatment to ensure no solids deposition on boiler metallurgy

DMDS Chemical consumed in hydro-processing unit for catalyst passivation

Solution tank or tote tank, with containment berms

Filming amine Protection of steam condensate piping throughout the plant.

Stored in tote tanks.

Flocculent Settling agent to be used in raw water treatment


Fluxant Gasifier fine slag removal – used as a fluxant in the gasification reactors to reduce ash melting.

Stored near gasifier in bin with containment berm

Ion exchange resin MBIX for feedwater treatment

Provided in multi-wall bags and stored in warehouse. Used in MBIX vessels with containment, as required

Neutralizing amine Protection of steam condensate piping throughout the plant

Stored in tote tanks

Oxygen scavenger Scavenging of oxygen in the boiler water treatment and metal passivation


Oxidant Used in IWT plant to ensure that the bio-treaters operate correctly


Polyelectrolyte Chemical precipitation Mixing or solution tanks, with containment berms

PSA adsorbent Hydrogen purification Typically on-time delivery for use. Provided in bins or large bags. Used in process vessels

Sodium phosphate Boiler water treatment for hardness slippage and pH control


Schedule 1

Sulphuric acid Cooling tower pH control, RO feed pH control, MBIX regeneration.


Schedule 1, NPRI

Vapour phase cleaning chemical

Used to clean vessels and piping and

Mixing or solution tanks, with





exchanger for maintenance.

containment berms

Note: CEPA (Canadian Environmental Protection Act) PSL2 (Priority Substances List 2) NPRI (National Pollutant Release Inventory)

B.10 Health, Safety and Environmental Management System and Contingency Plans

B.10.1 Overview

The NLP is committed to achieving high levels of HSE performance during the design, construction, operation and decommissioning of the Project. As the Project operator, and on behalf of the NLP, Synenco is developing and implementing an HSE Management System that will guide its HSE management activities throughout the Project. This section outlines Synenco’s approach to the development and implementation of its HSE Management System.

B.10.2 HSE Leadership and Accountability

Synenco is a responsible, performance-driven operator committed to operational excellence, public and worker safety, and social and environmental responsibility. These commitments are aligned with Synenco’s Mission and Vision, and have been discussed in previous public disclosure documents issued for the Project.

Specifically, Synenco is committed to:

conducting business activities with openness, honesty and integrity; protecting the health and safety of our workers and other people living in the

region; minimizing effects on the environment through innovation and by integrating

environmental considerations into every business aspect; meeting or exceeding all regulatory requirements; respecting community and stakeholder concerns; and working collaboratively with various levels of government, other operators and

affected communities to address issues associated with the proposed Project.

Synenco’s organizational structure reflects its commitment to HSE performance and continuous improvement. Synenco’s Board of Directors has established a Health,



Safety Environment Committee, comprised of all of the Directors, that is responsible for oversight of HSE matters.

B.10.3 Health, Safety and Environment Management System

The Project HSE Management System is being designed to implement all HSE-related operational integrity, regulatory compliance, and corporate commitments throughout the design, construction, operations and decommissioning phases of the Project. The HSE Management System will also be central to the effective management of change and continuous HSE performance improvement throughout the life of the Project.

The HSE Management system will be based on:

Synenco’s corporate HSE performance and continuous improvement commitments;

federal and Alberta occupational health, safety and environment regulatory requirements; and

the principles of ISO 14001 Environmental Management System (EMS) and CSA Z1000-2006 Occupational Health & Safety (OH&S) Management.

Synenco’s HSE Management System has five major system elements as shown in Figure B.10.3-1.

A summary of the specific plans, programs, and components included in each of these elements is provided in Figure B.10.3-2

B.10.4 HSE and Related Corporate Policies

Consistent with Synenco’s corporate Mission and Vision, Synenco is developing the following two policy documents:

a Corporate Responsibility Policy outlining governance and business practices, labour, environment, health and safety practices, community and stakeholder engagement practices; and

a Code of Conduct Policy outlining minimum expectations of behaviour and performance.

These corporate policies will guide the development of the HSE Management System.

1



B.10.5 Planning

Three main factors affect planning for HSE performance: corporate HSE goals and objectives; regulatory requirements; and corporate and non-legal requirements (e.g., industry standards and best practices).

B.10.5.1 Corporate HSE Goals and Objectives

Synenco is committed to setting specific, measurable HSE performance targets that ensure that real improvements in performance are being made and that maximum benefit is being obtained from the funds invested in HSE programs. As part of the HSE Management System, Synenco will establish corporate HSE objectives and targets annually. These goals will be designed to ensure that the performance expectations outlined in the applicable corporate policies regarding HSE are met.

Key safety performance indicators will include a combination of leading and lagging indicators, such as:

positive safety activities including job safety and hazard assessments, near misses and hazard alert reporting, safety meetings and worker training and similar activities.

total recordable injuries – employees (TRI) and lost time injuries - employees and contractors (LTI);

recordable motor vehicle accidents (MVA); and

Key environmental performance indicators will include indicators related to:

spills and pipeline releases; air emissions, including greenhouse gases; water use; waste management and reduction; and site reclamation.

Key social responsibility indicators are expected to include:

local employment and business opportunities; community investment; completion of stakeholder commitments; and number of, and response to, stakeholder concerns.



B.10.5.2 Regulatory Requirements

Relevant regulatory requirements, license and approval conditions, industry standards and operating practices will be identified in order to maintain regulatory compliance and ensure due diligence. The regulatory compliance objectives of the HSE Management System will be to:

identify areas of legal responsibility that are relevant to the Project; ensure that workers (employees, service providers, contractors, consultants)

understand their legal responsibilities; ensure copies of key legislation, regulations and guidelines are available to all

workers; ensure that the terms and conditions of permits and approvals are reviewed and

understood by relevant workers prior to commencing work; and ensure that no activities requiring regulatory approval commence or continue

without the appropriate regulatory approvals.

The HSE Management System will also establish processes to ensure that regulatory requirements are identified, interpreted and communicated to relevant staff on a regular basis.

B.10.5.3 Industry Practices and Corporate Expectations

The HSE Management System will address non-regulatory requirements such as corporate expectations and industry standards and best practices.

B.10.6 Implementation and Operations

Synenco is committed to an integrated approach to HSE management, as this is central to meeting corporate HSE commitments. Work is underway to develop plans and programs in the following areas to ensure all aspects of the HSE Management System are linked:

Occupational Health and Safety; Environmental Protection; Emergency Preparedness and Response; Asset Integrity; Stakeholder Involvement; and Worker Competency and Training.



The following sections briefly describe the objectives and scope of each of the core program elements.

B.10.6.1 Occupational Health and Safety

Worker and public safety is a priority. The objectives of the HSE Management System’s occupational health and safety programs are to:

develop and implement practices and procedures to address all relevant occupational health issues;

identify and mitigate hazardous conditions or procedures at the Project worksite and establish appropriate hazard control measures;

ensure that competent contractors are hired and that they are made aware of the Project-specific commitments and HSE Management System expectations; and

maintain effective communications with all parties such that prime contractor responsibilities are met.

Specific programs, practices and/or procedures will be developed for each of the following areas:

site safety management, including Management of Change (MOC), Operation Readiness Planning (ORP) and Pre-start-up Safety and Environment Reviews;

hazard management (including identification, assessment and control); contractor management; basic safety rules and requirements; and plans, practices and procedures including working alone, drug and alcohol

testing, and transportation safety (i.e., planning of staff and contractor movement, vehicle safety and journey management, and site traffic control).

Project-specific OHS programs will comply with the Alberta Occupational Health and Safety Act, regulations and Code. Programs will emphasize the implementation of a proactive hazard management system during each phase of development, including planning and design. A targeted program of formal hazard analysis will be developed as per CSA Q634 M, Risk Analysis Requirements and Guidelines, and CSA Q850, Risk Management; Guideline for Decision Makers.

As part of Synenco’s commitment to effective HSE management, the HSE Management System will include a detailed MOC process, a supporting database and the capability training needed to ensure that personnel can implement the process. Effective MOC processes are integral to ensuring that high risk events are reduced to the lowest possible level.



B.10.6.2 Environmental Protection

The HSE Management System will establish environmental programs needed to meet corporate commitments and goals, and comply with regulatory requirements.

The objectives of these programs are to:

identify environmental requirements for operations as identified through the Environmental Impact Assessment (EIA);

obtain all required regulatory approvals prior to commencing work; provide the required equipment and procedures to manage and mitigate

environmental effects of operating activities; implement plans and programs consistent with requirements identified under the

EIA, and the conditions of all regulatory approvals; and ensure that all incidents (e.g., spills) are reported, and that any required clean-up

starts immediately to mitigate any adverse environmental effects.

Specific programs will be developed for each of the following areas:

environmental assessments, licenses and approvals; spill management, including spill prevention, reporting and clean-up; waste management, including reduction of waste generation, recycling and

handling; air quality, including emissions control and energy conservation; water management; lease and right-of-way management, including vegetation management, water

crossings and runoff; natural and historic resource protection, including water quality, species at risk,

wildlife and fisheries protection; and archaeological resources; and liability management and site reclamation.

Project plans and programs will comply with all provincial and federal environment-related legislation, including Alberta’s Environmental Protection and Enhancement Act and the Water Act.

B.10.6.3 Emergency Preparedness and Response

Synenco’s Corporate Emergency Response Plan (ERP) is provided in Volume 2, Appendix 5. Given the fact that the Project is still in the early stages of engineering



design, the ERP will continue to be refined and improved as more information becomes available.

The Corporate ERP will include policies, plans and programs for emergency preparedness and response. The objectives of the emergency preparedness and response programs are to:

ensure immediate, competent response and handling of emergencies; minimize the danger to the public and workers; maintain effective communications with all parties in an emergency; and use the combined resources of internal and external services including other

area operators and the regional oil spill cooperative.

Programs will include:

first aid, fire fighting and emergency equipment; mutual aid; implementation planning, including risk assessment and stakeholder

consultation; emergency evacuation plans for all corporate and field offices and facilities; and corporate emergency response plan, including security.

Site-specific plans will be developed based on a full range of potential emergencies and will address response to non-routine situations including:

worker injuries and incidents; transportation incidents; and operational upsets, malfunctions and incidents.

Plans will be based on the Incident Command System model. Communication will be based on the requirements of EUB Directive 071 and the proponent’s community consultation commitments. In addition, Synenco is committed to developing a formal crisis communication plan.

The emergency preparedness and response programs will be designed to comply with relevant regulations and requirements including:

EUB Directive 071 and related Board requirements, CSA Z-731-03 - Emergency Preparedness and Response,



Canadian Environmental Protection Act (CEPA) and the Environmental Emergency (E2) planning requirements;

Alberta Workplace Health & Safety Code Part 7; and Sturgeon County emergency planning and response requirements.

Synenco also recognizes that the requirements of the Security Management Regulation, AR 249/2004 may also need to be addressed. Corporate and site-specific emergency plans will be submitted to the EUB for review and approval prior to commencing on-site construction and production activities.

B.10.6.4 Asset Integrity Management

The Project-specific HSE Management System will establish formal quality assurance and quality control programs needed to establish and maintain equipment integrity. These programs are integral to ensuring that high consequence, low frequency events are reduced to the lowest possible level during each Project phase beginning with planning and design.

The objectives of these programs are to:

ensure appropriate construction, operating and maintenance systems are in place and functioning to assure regulatory compliance;

confirm conformance with corporate policies and industry standards and guidelines;

identify actual or potential risks and provide recommendations for corrective action; and

demonstrate due diligence with respect to the operation and maintenance of the Project equipment.

Specific quality management programs will be developed for each of the following areas:

OHS code specifications and certifications (with an emphasis on manufacturers’ operating and maintenance recommendations);

pressure equipment Integrity Management Plan (IMP); pipeline Operation and Maintenance (O&M) ; storage tank management; electrical Quality Management Plan (QMP); and measurement and monitoring equipment.



Equipment will be designed to comply with relevant Acts, regulations and guidelines including:

Alberta’s Safety Codes Act (including the Pressure Equipment Safety Regulation);

Oil Sands Conservation Act and regulations; relevant Directives established by the EUB; Alberta’s Pipeline Act (including the Pipeline Regulation); and CCME standards and guidelines.

In addition, the design of Upgrader facilities will be in accordance with the latest edition of ASME B31.3 “Pressure Piping Systems” and the latest revision of any relevant codes and standards published by:

Canadian Standards Association (CAN/CSA); API; American Society of Mechanical Engineers (ASME); American National Standards Institute (ANSI); and American Society for Testing and Materials (ASTM).

B.10.6.5 Stakeholder Involvement

Synenco is committed to understanding and responding to stakeholder concerns regarding its HSE performance. Consequently, the stakeholder and community engagement program is an integral component of the Project-specific HSE Management System.

The specific objectives of the community and stakeholder engagement program are to:

identify Project-specific community and stakeholder issues and concerns; provide communities and stakeholders with clear and timely information about

the Project; provide communities and stakeholders with opportunities and venues to provide

comments on the Project; build long-term mutually beneficial partnerships with communities and

stakeholders potentially affected by the nature and extent of the Project; identify and participate in long-term, meaningful and sustainable mechanisms

that benefit the quality of life for people living and working in the region; and obtain community and stakeholder support for the Project.



Synenco’s approach to stakeholder and community engagement is described in detail in Volume 2, Part C.

B.10.6.6 Worker Competence and Training

Synenco requires that all workers receive appropriate training, including those whose work may contribute to effects on worker and public safety, or the environment.

The objectives of training programs are to:

motivate high performance through information, instruction and practice; identify issues and employee training needs, and develop training plans that

address these needs; maintain appropriate documentation of training completed; and ensure training programs are revised as required to conform to corporate policies

and regulatory requirements.

The following programs and procedures will be developed to address worker competency:

HSE Handbook; employee and contractor orientations; core HSE training; corporate codes of practice for critical HSE practices, as required by Alberta

Human Resources and Employment’s Workplace Health and Safety department; worker capability development required to implement Synenco’s safe operating

procedures; relevant Industry Recommended Practices (IRP); and supervisory training and development, including regularly scheduled

management/supervisor meetings to review HSE program requirements and implementation.

B.10.6.7 Contractor Management

Synenco recognizes that during construction of the Project, the primary workers involved will be contractors. Consequently, Synenco’s commitment to worker safety means that contractor safety is a priority. Contractor Management will be integrated throughout Synenco’s HSE Management System.



The Contractor Management program objectives include:

ensuring that Synenco’s commitment to safety is communicated and understood by all contractors;

ensuring that contractors understand and comply with Synenco’s HSE Management System, including regulatory requirements and commitments made to stakeholders;

ensuring that contractors have programs in place that are at least equivalent to Synenco’s HSE Management System programs, plans, practices and procedures; and

ensuring contractors are competent to complete assigned work.

The HSE Management System will:

identify Synenco’s prime contractor role and responsibilities in the corporate HSE policies and management system documentation;

identify Synenco’s contractor management strategy in all relevant HSE Management System plans, programs and documentation;

develop Project-specific hazard management plans, and associated standards and checklists in conjunction with contractors;

develop and deliver contractor orientations and qualification/training programs; monitor contractor performance relative to Synenco’s HSE Management System

expectations and safety performance indicators, and provide feedback to contractors on an ongoing basis; and

include contractor management and performance in management review activities.

B.10.7 Monitoring and Review

To ensure the effective implementation and continuous improvement of the HSE Management System, the following programs will be established:

HSE Meetings and Communications; Incident Reporting and Follow-up; Compliance Auditing and Inspections; Performance Measuring, Monitoring and Reporting; and Records Management.



B.10.7.1 HSE Meetings and Communications

Effective communication is central to the success of Synenco’s HSE Management System. All workers, employees or contractors, from corporate officers to managers, supervisors and front line workers, will be made aware of Synenco’s corporate HSE commitments and HSE Management System expectations. Workers who have management system implementation responsibilities and/or have the potential to have a substantial influence on safety or environmental performance will be provided with the relevant information to ensure conformance with Synenco’s HSE Management System.

The objectives of communication programs will be to:

ensure workers know the hazards and the control measures for any given task or job;

provide opportunities for the sharing of HSE-related information; provide opportunity for all workers to raise and address HSE issues; and provide a process for monitoring and improving HSE performance and issues.

Synenco will develop targeted processes to provide opportunities for communication, and to ensure that communication is effective. Key processes include:

HSE (safety) tailgate, pre-job and general or loss control meetings; and safety bulletins and information.

B.10.7.2 Incident Reporting and Follow-up

Timely and appropriate response to incidents and effective mitigation of potential effects are necessary to meet regulatory requirements and public expectations and to minimize financial losses.

The objectives of the incident reporting and investigation program are to:

ensure incidents with the potential to affect worker health and safety, the public, the environment and other aspects of the company's operations are promptly reported;

ensure incidents are investigated to determine the causes and identify any required corrective actions;

ensure follow-up to confirm that corrective actions are completed; communicate findings and mitigation recommendations; evaluate current HSE Management Systems based on new findings; and improve programs as required.



Synenco will establish and maintain programs to facilitate effective incident reporting and investigation. These programs will allow analysis of incident history so that frequencies, trends, and common causes can be identified.

B.10.7.3 Compliance Audits and Inspections

Synenco will establish formal audit and compliance inspection programs to manage all activities that could influence worker and public safety and the environment.

The audit and inspection program objectives will be to:

confirm compliance with applicable legislation and regulatory requirements; confirm conformance with corporate and industry policies, standards and

guidelines; ensure appropriate HSE management and control systems are in place and

functioning; identify actual or potential risks and provide recommendations for corrective

action; and demonstrate due diligence in the administration of regulatory requirements and

Synenco commitments.

Compliance audits and inspections will be applied to all components of the HSE Management System, with specific focus on the following areas:

Occupational Health and Safety; Environmental Protection ; Asset Integrity Management; and Security.

B.10.7.4 Performance Measuring, Monitoring and Reporting

To ensure that HSE objectives are being met and that continuous performance improvements are being achieved, indicator measurement, monitoring of key activities and reporting will be implemented.

The objectives of measurement, monitoring and reporting are to:

ensure compliance with regulatory monitoring and reporting requirements; demonstrate management commitment to HSE performance; address information requests and concerns with respect to HSE performance; raise awareness of HSE policies, objectives, and programs; and



report to workers and stakeholders about the HSE Management System and performance, as appropriate.

Synenco will establish and maintain programs to communicate HSE management activities and performance including:

measurement and monitoring programs with an emphasis on contractor safety and environmental monitoring as required to address specific operating functions and effects;

internal reporting systems between various levels and functions of the company; and

processes for external communication on its significant HSE aspects as required.

B.10.7.5 Records Management

Records are required to demonstrate successful implementation of the HSE Management System, ongoing HSE performance and due diligence. Document and records management will facilitate management of the complex range of information generated by the HSE Management System. Programs will be developed to control electronic and paper records in accordance with HSE Management System.

B.10.7.6 Review and Improvement

Periodic management review will be conducted to facilitate continuous improvement in HSE performance, and ensure the suitability and effectiveness of the HSE Management System.

The objectives of the review are to:

inform senior management about HSE performance on a regular basis; develop and/or update corporate HSE commitments, strategies and goals on a

planned and periodic basis; and ensure sufficient resources for effective HSE Management System

implementation.

The review will consider:

results from incident investigations, non-conformances, audit results and the completion of corrective actions;

benchmarking of actual performance against corporate commitments and goals; and



new/revised legislative or regulatory requirements and/or industry practices, and stakeholder expectations, and the associated influence on plans and programs.

B.10.8 Implementation of HSE Management System

A five-year plan has been developed to guide the development and implement of the HSE Management System. The plan addresses three distinct phases of activities over the next five years including:

Years 1 and 2 (2006/2007): HSE Management System Design Stage

Review requirements and prepare plan and program documents. Identify and address approval requirements.

Years 3 and 4 (2008/2009): Project Construction Stage

Initiate implementation of plans and programs with an emphasis on construction activities and contractor safety.

Year 5 (2010): Start-up and Initial Operations Stage

Assess preliminary plan and program results. Identify and target areas of concern with an emphasis on Project start-up and ensuring operational plans are functioning as required.

B.11 Approach and Application of Adaptive Management

Inherent in the application of new technology and approaches is the ability to address uncertainty, since there is always less certainty about the actual performance of new approaches in the field. Adaptive management is the preferred tool for addressing uncertainty and will be used by the NLP over the course of the Project life. Adaptive management is a structured process used to systematically test assumptions in order to learn and adapt to unexpected results. Adaptive management involves a six step cycle:

assess operational needs and environmental issues; develop management objectives and select the appropriate technology or

management practice; implement that technology or management practice; monitor the results; evaluate the effectiveness of the design against management objectives; and adjust the design as necessary and repeat the cycle.



The adaptive management approach is functionally very similar to the “plan-do-check-act” cycle upon which HSE management systems are typically based (Section B.10). The adaptive management cycle differs slightly in that adaptive management provides a somewhat better structure for managing uncertainty and testing assumptions, including management objectives.

Adaptive management principles will be applied in the following areas:

changing environmental regulatory requirements; consideration of the NSR Instream Flow Need (efficiency and effectiveness of

water reuse and recycle system); predictions regarding energy efficiency and air emissions; and

management of cumulative environmental effects in the region.

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