Material and Energy Balance for an Oil Sands Surface Mining and Bitumen Extraction ... · 2020. 7. 7. · Guidance for Completing Specified Gas Compliance Reports (Version 7.0, January

Material and Energy Balance for an Oil Sands Surface Mining and Bitumen Extraction Reference Facility

March 18, 2020

Prepared for:

Prepared by:

Revision Description Author Quality Check Independent Review 0 For Client

Approval BT 13/12/19 BT 13/12/19 GW 13/12/19

1 Final BT 18/03/20 BT 18/03/20 GW 18/03/20

MATERIAL AND ENERGY BALANCE FOR AN OIL SANDS SURFACE MINING AND BITUMEN EXTRACTION REFERENCE FACILITY

This document entitled Material and Energy Balance for an Oil Sands Surface Mining and Bitumen Extraction Reference Facility was prepared by Stantec Consulting Ltd. (“Stantec”) for the account of COSIA (the “Client”). Any reliance on this document by any third party is strictly prohibited. The material in it reflects Stantec’s professional judgment in light of the scope, schedule and other limitations stated in the document and in the contract between Stantec and the Client. The opinions in the document are based on conditions and information existing at the time the document was published and do not take into account any subsequent changes. In preparing the document, Stantec did not verify information supplied to it by others. Any use which a third party makes of this document is the responsibility of such third party. Such third party agrees that Stantec shall not be responsible for costs or damages of any kind, if any, suffered by it or any other third party as a result of decisions made or actions taken based on this document.

Prepared by (signature)

Bhurisa Thitakamol, PhD., P.Eng

Checked by (signature)

Bhurisa Thitakamol, PhD., P.Eng

Reviewed by (signature)

Gary Wheating, P.Eng


Table of Contents

EXECUTIVE SUMMARY ............................................................................................................... I

ABBREVIATIONS ......................................................................................................................1.1

1.0 INTRODUCTION ...........................................................................................................1.2

2.0 MATERIAL AND ENERGY BALANCE ............................................................................2.1

3.0 METHODOLOGY ..........................................................................................................3.4 3.1 INPUTS AND ASSUMPTIONS ......................................................................................... 3.4 3.2 GHG EMISSIONS CALCULATION ................................................................................ 3.8

3.2.1 Stationary Combustion Emissions ............................................................. 3.9 3.2.2 Fugitive Emissions ...................................................................................... 3.9

4.0 FLOW DIAGRAM ..........................................................................................................4.1

5.0 CONCLUSION ..............................................................................................................5.1

LIST OF TABLES Table 3-1 Key Inputs and Assumptions for the Ore Preparation and Extraction

Process ..................................................................................................................... 3.5 Table 3-2 Key Inputs and Assumptions for the Utility Plant .................................................. 3.7 Table 3-4 Fugitive Emission Factors from Mine Face .......................................................... 3.9 Table 3-5 Fugitive Emission Factors from Tailing Ponds ...................................................... 3.9 Table 4-1 Output Summary ................................................................................................... 4.1

LIST OF APPENDICES

APPENDIX A MATERIAL AND ENERGY BALANCE DIAGRAMS....................................... A.1

i

Executive Summary

This report provides a description of an oil sands surface mining (known as “Open Pit mining”) and bitumen extraction process, and a methodology used to create material and heat balances and calculate GHG emissions for the process. This work is based on Paraffinic Froth Treatment (PFT) and Naphthenic Froth Treatment (NFT) reference facilities producing 200,000 barrels per day (bbl/d) of bitumen for the four scenarios listed below.

• PFT – High Grade Ore in summer condition

• PFT – Low Grade Ore in winter condition

• NFT – High Grade Ore in summer condition

• NFT – Low Grade Ore in winter condition

The resulting Material and Energy balances are intended to facilitate the evaluation of GHG reduction opportunities and water and heat recovery possibilities by providing a common basis of process information needed for prospective technology developers to better quantify the benefits and complete the analysis of their technologies.

Stantec’s approach is to create Aspen HYSYS models and Excel spreadsheet calculators for the utility plant, for power, steam and hot water, of the reference facility to determine the natural gas consumption and the boiler feed water flow rate required by the ore preparation and extraction process, which are provided by CanmetEnergy. Stantec has collaborated with CanmetENERGY for their insight and knowledge of the mining extraction process. Their feedback on the following parameters were required to complete the Aspen HYSYS models and excel spreadsheet calculators of the utility plant.

• Steam flow rate

• Hot/warm process water flow rate

• Reclaimed water flow rate

• Heat requirement for ore preparation and extraction process

The iterative process between Stantec and CanmetENERGY was initiated to check and balance these process parameters until all the simulations and calculations matched. The key inputs and assumptions were extracted from COSIA’s internal database and industrial practices in oil sand industry, which are publicly available.

ii

The GHG emissions (tonnes CO2e) for all four scenarios were calculated for three emission categories as listed below following the completion of the analysis of the material and energy balance.

• Stationary Combustion Emissions (CO2) from the combustion of natural gas used for gasturbine generator, heaters and auxiliary boilers.

• Fugitive Emission (CO2 and CH4) from mine face and tailing ponds

The calculations were based on the Aspen HYSYS’s results, COSIA recommendations, and emission factors as per the Alberta Specified Gas Emitters Regulation (SGER)’s Technical Guidance for Completing Specified Gas Compliance Reports (Version 7.0, January 2014) and the 2019 National Inventory Report 1990 – 2017: Greenhouse Gas Sources and Sinks in Canada Part 2.


Introduction

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Abbreviations

bbl/d Barrels per day BFW Boiler Feed Water

CH4 Methane

CO2 Carbon Dioxide

CO2e CO2 equivalent COSIA Canada’s Oil Sands Innovation Alliance CW Cooling Water FSU Froth Settling Unit GHGs Greenhouse gases GTG Gas Turbine Generators GWP Global Warming Potential HFCs Hydrofluorocarbons HHV High Heating Value HRSG Heat Recovery Steam Generators IPS Inclined Plate Separator LHV Low Heating Value LPS Low Pressure Steam MPS Medium Pressure Steam N2O Nitrous oxide NFT Naphthenic Froth Treatment PFCs Perfluorocarbons PFT Paraffinic Froth Treatment PSC Primary Separation Cell PW Process Water SF6 Sulphur Hexafluoride SGER Specified Gas Emitters Regulation SRU Solvent Recovery Unit TSRU Tailing Solvent Recovery Unit


Introduction


1.0 INTRODUCTION

Canada’s Oil Sands Innovation Alliance (“COSIA”) has a vision to enable the responsible and sustainable growth of Canada’s Oil Sands while delivering accelerated improvement in environmental performance in greenhouse gases (GHGs), land, tailings and water through collaborative action and innovation. COSIA retained Stantec Consulting Ltd. (“Stantec”) to create Excel spreadsheet block flow diagrams with combined material and energy balance of the oil sands surface mining and bitumen extraction for Paraffinic Froth Treatment (PFT) and Naphthenic Froth Treatment (NFT) reference facilities producing 200,000 barrels per day (bbl/d) of bitumen for the four scenarios listed below.

• PFT – High Grade Ore in summer condition

• PFT – Low Grade Ore in winter condition

• NFT – High Grade Ore in summer condition

• NFT – Low Grade Ore in winter condition

The objective of these diagrams is to facilitate the evaluation of GHG reduction opportunities and water and heat recovery possibilities by providing a common basis of process information needed for prospective technology developers to better quantify the benefits and complete the analysis of their technologies.

Since the reference facility consists of two major areas – ore preparation and extraction process and utility plant, Stantec has collaborated with CanmetENERGY for their insight and knowledge on the mining extraction process. Their feedback on the required amount of steam and process water as well as the heat requirement for the ore preparation and extraction process are needed to complete Stantec’s Aspen HYSYS models and Excel spreadsheet calculators for the utility plant. This creates an iterative process required to converge both Stantec’s models and CanmetENERGY’s calculations for a complete material and heat balance.

This report is prepared for COSIA to provide a description of surface mining and extraction process, and to explain a methodology used to create material and heat balances and calculate GHG emissions. The report concludes with the complete Material and Energy balances for all four scenarios. Details regarding the development of the reference facility and the differences associated with PFT and NFT processes are not part of this work.


Material and Energy Balance


2.0 MATERIAL AND ENERGY BALANCE

The Material and Energy balances for each scenario of the reference facility has two major areas, each represented by five sections. Sections 1 – 4 represent the ore preparation and extraction process and Section 5 highlights the utility plant. The following is a brief discussion of each section.

Section 1: Ore Preparation: Conditioning, Crushing and Conveying

Once the mined oil sand is hauled to the processing plant, it will be first processed in an Ore Preparation Plant, where clumps of oil sands are broken up into loosely crushed oil sands by the Crusher and dumped onto a conveyor. Then, hot and warm water are added and vigorously mixed to this crushed oil sand, producing a wet, aerated slurry in the Rotary Breaker. Caustic soda is also added to help improve the bitumen recovery as the slurry pH is raised. Any oversized material (such as petrified wood, rocks or large chucks of ice) that could not be re-crushed will be separated by screening and then rejected as the Breaker Reject. The Hydrotransport Pump will pump this wet slurry through hydrotransport pipelines to the Extraction Process. These pipelines are designed to provide additional residence time for extra mixing and aeration, and mechanical shear to further break down the oil sand lumps, releasing bitumen from the sand.

Section 2: Primary Extraction Process

The bitumen in the oil sand slurry is recovered in the Primary Separation Cell (PSC), while the solids such as sand will be rejected to the tailings plant. This PSC is a large cone-bottomed vessel that employs a simple water-based gravity separation process to produce three streams – overflow, middlings and underflow. The bitumen released from the sand tends to attach to free air bubbles and rises to the top of the vessel, forming a clean bitumen froth overflow stream. This overflow stream then flows to the Deaerator to reduce the air content. Steam is also added to the Deaerator to help reduce the bitumen froth viscosity and destabilize the air bubbles. This deaerated intermediate bitumen froth product will be pumped by the Deaerated Froth Pump to the Froth Treatment Stage for further bitumen recovery. The middlings stream from the middle of the PSC, which is comprised of water and a still higher bitumen content than the underflow, is sent to the Flotation & Cyclone for secondary bitumen recovery. The underflow containing mostly solids and residual bitumen will be rejected at the bottom of the PSC and sent to the tailings pond.

Section 3: Secondary Extraction Process – Froth Treatment

Due to a high content of solids and water, the intermediate bitumen froth product from the Primary Extraction Process needs to be cleaned using the Froth Treatment Process where a hydrocarbon-based gravity separation technique is used to remove fine solids and water from the bitumen. Paraffinic and Naphthenic solvents are the two main types of hydrocarbons used




to add and mix with the bitumen froth to reduce the viscosity of the mixture in the Froth Treatment process. In the solvent extraction process, bitumen is soluble in the solvents; but water is not. Oil phase and water phase are formed. Sands tend to stay in the water phase. This improves the gravity separation between fine solids/water and the bitumen/hydrocarbon. Hydrocarbon is then recovered from the bitumen/hydrocarbon mixture and recycled back for reuse, leaving relatively clean diluted bitumen product ready for use in either an upgrader or a refinery depending on the product quality.

Paraffinic Froth Treatment (PFT)

In PFT, the paraffinic solvent containing primarily paraffin hydrocarbons is added to the bitumen froth in the Froth Settling Unit (FSU). The overflow of the very rich bitumen/solvent mixture from the FSU is sent to the Solvent Recovery Unit (SRU) to recover a majority of the solvent and produce a final clean bitumen product ready for an upgrader. The underflow containing mostly water and solids with a small amount of solvent is sent to the Tailing Solvent Recovery Unit (TSRU) to recover any residual solvent prior to disposal in the tailings pond. Steam is injected to both the SRU and TSRU for solvent recovery. The recovered solvent, together with the fresh solvent, will be sent to the FSU.

Naphthenic Froth Treatment (NFT)

In NFT, the naphthenic solvent containing primarily naphthene hydrocarbons is added to the bitumen froth in the Inclined Plate Separator (IPS) to produce a good quality overflow ready for an upgrader. The underflow from the ISP still needs to be processed through the Centrifuge Unit to improve bitumen recovery. Any residual solvent remaining in the bottom discharge of the Centrifuge Unit will be recovered in the Naphtha Recovery Unit (NRU), prior to disposal in the tailings pond. Steam is injected in the NRU for solvent recovery. The recovered solvent, together with the fresh solvent, will be sent to the IPS.

Section 4: Tailings Unit

The tailings pond receives the tailings from the Extraction Process. It will allow any fine solids and coarse sand to settle down to the bottom, while the reclaimed water is sent to the Recycled Water Pond for reuse.

Section 5: Utility (Steam Generation)

The main objective of this unit is to produce steam for use as a heating and stripping medium in the process. Steam is produced using a combination of auxiliary boilers and a cogeneration facility, which has two trains each containing gas turbine generators (GTG), duct burners and heat recovery steam generators (HRSG). Natural gas is used to fuel for the GTGs, duct burners and auxiliary boilers.

Medium Pressure Steam (MPS) is used partially as stripping steam and to a larger extent for process heating in the extraction process, while Low Pressure Steam (LPS) is only used for process heating




to produce hot water in the water distribution system. The condensed steam is returned as process condensate and recycled as boiler feed water (BFW). Steam conditions are listed below:

• MPS conditions are at 225oC and 2100 kPag

• LPS conditions are 210oC and 1390 kPag

Water Distribution System

Makeup water drawn from natural resources such as the nearby river is sent to the Raw Water Pond Water Treatment Plant prior to being split into two main streams. One is mixed with the return process condensate and then fed to the auxiliary boilers and the HRSGs as BFW. The other stream is combined with the reclaimed water from the Tailings Unit, which is Process Water (PW). This PW is heated, either by a series of heat exchangers, or by mixing with hot water as explained below prior to distribution to the Ore Preparation and Extraction process as Hot PW and Warm PW.

The PW from the Recycled Water Pond must flow through the following heat exchangers to achieve the final temperature of Hot and Warm PWs:

• PW/CW Exchanger recovering heat from Cooling Water (CW) by cooling it down from 60oC to30oC. The cold CW is sent to the three coolers and for process use in the mining process. The warmCW return then rejects its heat in the PW/CW Exchanger to complete the cycle.

• PW/Condensate Exchanger exchanging heat with LPS condensate; and

• PW/LPS Exchanger exchanging heat with LPS to reach approximate 80oC Hot PW.

A certain quantity of Hot PW is stored in the Hot Water Tank, the rest is partially mixed with the PW to obtain 45oC Warm PW, which is stored in the Warm Water Tank. Any remaining PW will be sent out for cooling requirements.


Methodology


3.0 METHODOLOGY

To successfully deliver a complete material and energy balance for the 200,000 bbl/d oil sands surface mining and extraction Paraffinic Froth Treatment (PFT) and Naphthenic (NFT) reference facilities, Stantec developed an Aspen HYSYS model for the utility plant, while CanmetEnergy separately developed their own internal calculations and simulation models for the ore preparation and extraction process. The connections between these two processes are listed below.

- The required steam from the HRSGs and the auxiliary boilers used for stripping steam forsolvent recovery in the Froth Treatment process and deaerating steam in the Deaerator aswell as process heating steam for heating the solvents prior to injecting to the FrothTreatment process, and to the FSU overflow stream in the PFT facility. Only the condensateof the process heating steam will return to the utility plant as the BFW

- The hot/warm process waters generated from a series of heat exchangers in the waterdistribution system using LPS steam and its condensate

- The reclaimed water from the Tailing Pond

As a result, the iterative process between Stantec and CanmetENERGY was initiated to check and balance these process parameters until all the simulations and calculations matched. The real operation parameters (as well as given from open literature) are always in a range. The tolerance of some of the numbers in this report are approximately ±7%. Stantec varied the natural gas consumption and the BFW flow rate to the HRSGs and Auxiliary Boilers based on the inputs and assumptions summarized in Section 3.1 to meet the steam and hot/warm process water requirements for the ore preparation and extraction process.

3.1 INPUTS AND ASSUMPTIONS

Inputs and assumptions as used in the models and calculation are listed in Table 3.1 for the ore preparation and extraction process and Table 3.2 for the utility plant are extracted from COSIA’s internal database and industrial practices in oil sand industry, which are publicly available.


Methodology


Table 3-1 Key Inputs and Assumptions for the Ore Preparation and Extraction Process

Parameter Unit Reference Facility

Source PFT NFT

Oil Sands Feed Temperature oC 5 (PFT-High Grade),

-3 (PFT-Low Grade)

4 (NFT-High Grade)

1 (NFT-Low Grade)

COSIA internal database

Bitumen Density tonne/m3 1.007 Tech Frontier 2015 Update

Cp, sand J/gK Composition-averaging method from quartz silica sand and clay

Engineering Toolbox and Oilsands Magazine

Cp, bitumen J/gK 1.45 M. R. Cervenan, F. E.Vermeulen, and , F. S. Chute,Thermal conductivity andspecific heat of oil sandsamples, Canadian Journalof Earth Sciences, 1981, 18(5):926-931

Solvent Composition mol fr. PFT NFT NFT – Jiawei Du and William R. Cluett, Modelling of aNaphtha Recovery Unit (NRU)with Implications for ProcessOptimization, Processes,2018, 6, 74

- i-Pentane mol fr. 0.33 N/A

- n-Pentane mol fr. 0.33 N/A

- n-Hexane mol fr. 0.33 0.12

- Toluene mol fr. N/A 0.03

- Methylcyclopentane mol fr. N/A 0.07

- Methylcyclohexane mol fr. N/A 0.11

- n-Heptane mol fr. N/A 0.11

- 2-Methylhexane mol fr. N/A 0.10

- o-Xylene mol fr. N/A 0.00

- m-Xylene mol fr. N/A 0.03

- n-Octane mol fr. N/A 0.06

- 1-Methyl-1-ethylcyclopentane

mol fr. N/A 0.06

- 2-Methylheptane mol fr. N/A 0.09

- 2,2,5-Trimethylhexane mol fr. N/A 0.11

- n-Nonane mol fr. N/A 0.04

- n-Decane mol fr. N/A 0.03

- 1-Methyl-3-ethylbenzene mol fr. N/A 0.04

Total mol fr. 1.00 1.00


Methodology



Source PFT NFT

Solvent Density tonne/m3 0.624 0.665 PFT – Tech Frontier 2015 Update, isopentane at 20oC, NFT – Engineering Toolbox, Naphtha

Cp, solvent J/gK 2.30 2.10 PFT, NFT – Aspen HYSYS properties

Solvent Temperature oC 20 (High Grade), 2 (Low Grade)

48 COSIA internal database

Solvent : Bitumen ratio wt/wt 1.65 0.7 PFT, NFT - Industrial Practice

Solvent Losses : Bitumen Produced

vol/vol 0.3 Less than 0.4 PFT – COSIA internal database, NFT - AER Directives

Asphaltene Rejection % Approx. 7 0 PFT, NFT – COSIA internal database

Asphaltene Content in Bitumen Product

% 12 N/A PFT – COSIA internal database

Water and Solids in Diluted Bitumen Products

% Less than 0.5 3 PFT, NFT – COSIA internal database


Methodology


Table 3-2 Key Inputs and Assumptions for the Utility Plant


Source High Grade Low Grade

Natural Gas Requirement per Plant COSIA’s internal database - GTG GJ/h HHV 774 1045

- HRSG and Duct Burner GJ/h HHV 336 537

Electricity MW 127 175

PFT NFT PFT NFT

Natural Gas Temperature oC 25 10 2 10 COSIA’s internal database and CanmetENERGY’s calculation

Air Temperature oC 25 10 2 10

Make-up Water Temperature oC 25 10 2 10

Hot Water Flow Rate T/h 5,918 5,045 8,195 8,271

Warm Water Flow Rate T/h 4,396 3,533 1,716 6,464

Cooling Water Flow Rate T/h 6,217 5,599 7,604 6,849

Hot Water Temperature oC 80 80 80 80

Warm Water Temperature oC 45 45 45 45

Cooling Water Temperature oC 25 10 2 10

MPS Stripping Steam T/h 144 105 148 105

Boiler Blowdown Flow Rate T/h 21 20 50 28


Methodology


3.2 GHG EMISSIONS CALCULATION

The reference facility is a fictitious stand-alone mine excluding integration with either an upgrader or adjacent in-situ operations with a fixed size of 200,000 bbl/d bitumen. It also has an on-site cogeneration unit using natural gas as a fuel to produce steam and electricity. The facility has natural gas fired equipment including boilers and building heaters, which are the main sources of GHG emissions onsite. In addition, the emissions calculation includes the emissions from mobile equipment for ore trucking using diesel as fuel and the fugitive emissions from mine face and tailing ponds.

GHGs emitted at the reference facility are mainly carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). There are no activities identified resulting in emissions of sulphur hexafluoride (SF6), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs).

Categories of GHG emissions sources include:

• Stationary Combustion Emissions (CO2) from the combustion of natural gas used for gasturbine generator, heaters and auxiliary boilers.

• Fugitive Emission (CO2 and CH4) from mine face and tailing ponds

The total quantity of each GHG species subject to each category in units of tonnes of the gas species is calculated as detailed below. Since the total GHG emissions for each source must be reported in tonnes of CO2 equivalent (tonnes CO2e), the global warming potential is used to multiply with each GHG emission using (Eq.1).

𝐸𝐸𝐸𝐸𝑦𝑦 = ∑ 𝐸𝐸𝑦𝑦−𝑝𝑝 × 𝐺𝐺𝐺𝐺𝐺𝐺𝑝𝑝𝑝𝑝 (Eq.1)

Where:

𝐸𝐸𝐸𝐸𝑦𝑦 = the total emissions for category y (tonnes of CO2e)

𝐸𝐸𝑦𝑦−𝑝𝑝 = the total emissions of a particular prescribed GHG species p from category y (tonnes of the particular prescribed GHG species p)

𝐺𝐺𝐺𝐺𝐺𝐺𝑝𝑝 = the global warming potential for the particular prescribed GHG species p, CO2 = 1, CH4 = 25 and N2O = 298 as per Alberta Specified Gas Emitters Regulation (SGER)’s Technical Guidance for Completing Specified Gas Compliance Reports (Version 7.0, January 2014)

y = a regulated source category

p = a prescribed GHG


Methodology


3.2.1 Stationary Combustion Emissions

The GHG emission from the stationary combustion is extracted from the Aspen HYSYS’s results. For GHG emissions credit from the cogeneration unit, it is calculated as per COSIA recommendations listed below:

• Deemed emissions from heat (DH) - Allocation to thermal output based on steamgeneration (assuming an 80% efficient boiler under SGER) to allocate emissions to thethermal output

• Deemed emissions from electricity (DE) - Allocation to electrical output based on thedifference between the total emission from cogeneration unit and the DH.

3.2.2 Fugitive Emissions

The emission factors in tonne CO2e provided in Tables 3.4 – 3.5 are used as a guideline to calculate the fugitive emissions from mine face and tailings ponds in this study. The finalized emission factors are still under evaluation.

Table 3-3 Fugitive Emission Factors from Mine Face

Condition CH4 (kg/m2/d) CO2 (kg/m2/d)

Low High Low High

High Grade 0 0.000294 0.0001333 0.007648

Low Grade 0 0.000904 0.000007085 0.0129

Table 3-4 Fugitive Emission Factors from Tailing Ponds

Reference Facility CH4 (kg/m2/d) CO2 (kg/m2/d)

Low High Low High

Paraffinic Biogenic* non-zero non-zero non-zero non-zero

Non-biogenic 0.00000024 0.000424 0.000743 0.009501

Naphthenic Biogenic 0.0002933 0.028757 0.003504 0.029262

Non-biogenic 0.000000105 0.000832 0.001081 0.03645

*Early stage microcosm studies conducted in 2019 (K.Budwill, Innotech) reflect paraffinic tailings ponds can generatebiogenic emissions. Further work needs to be done to confirm this observation is broadly applicable for inclusion in areference facility.


Flow Diagram


4.0 FLOW DIAGRAM

The material and energy flow diagrams are provided in Appendix A. Table 4.1 summarizes key results obtained from the flow diagrams for all scenarios.

Table 4-1 Output Summary

Parameter Unit PFT NFT

High Grade Low Grade High Grade Low Grade Bitumen Recovery Summary

Ore Preparation % 99.0 98.2 98.9 98.9

Primary Extraction % 94.6 92.3 98.0 98.0

Froth Treatment (without rejected asphaltenes)

% 98.4 98.4 98.2 98.2

Total Bitumen Recovery % 92.2 89.1 95.2 95.2

Asphaltenes Rejection % 7.6 7.7 0.0 0.0

Total Bitumen Recovery (with rejected asphaltenes)

% 85.1 82.3 95.2 95.2

Water Summary

Process Water – Cooling Water T/h 6,217 7,604 5,599 6,849

Process Water – Heated Water T/h 10,314 9,911 8,578 14,735

Reclaimed Water T/h 14,051 15,206 12,304 20,292

Raw Water T/h 2,480 2,309 1,873 1,292

BFW T/h 165 198 125 133

Boiler Blowdown T/h 21 50 20 28

Make-Up Water T/h 2,645 2,507 1,998 1,425

Condensate Return T/h 843 1,139 632 792

Fresh Water : Bitumen vol. /vol. 2.04 2.25 1.80 2.70

Cogen Energy Summary

Input - GTG GJ/h 1,547 2,090 1,547 2,090

HRSG GJ/h 672 1,074 672 1,074

Compressor GJ/h 12 16 12 16

Total GJ/h 2,231 3,180 2,231 3,180 Output - Electricity GJ/h 457 630 457 630

Steam GJ/h 1,321 2,044 1,383 1,993

Cogen Losses GJ/h 453 506 391 557

Total GJ/h 2,231 3,180 2,231 3,180


Flow Diagram


Parameter Unit PFT NFT

High Grade Low Grade High Grade Low Grade Boiler Energy Summary

Input GJ/h 1,407 1,473 583 388

Total GJ/h 1,407 1,473 583 388 Output - Steam GJ/h 1,222 1,372 530 353

Boiler Losses GJ/h 185 101 53 36 Total GJ/h 1,407 1,473 583 388

Flue Gas from Combustion

Cogen Flue Gas e3m3/h 2,163 3,343 2,278 3,247

Boiler Flue Gas e3m3/h 554 629 242 161

Exchanger & Cooler Duty

Process Water / Cooling Water GJ/h 755 1,365 1,224 2,190

Process Water / Condensate GJ/h 208 357 160 244

Process Water / LPS GJ/h 768 1,280 613 937

SRU Feed / MPS GJ/h 800 811 754 754

Solvent Feed / MPS, Heater GJ/h 321 415 41 43

Cooler x 3 GJ/h 1,356 1,366 372 396

Heat Rejection GJ/h 601 0 0 0

Other Process Use GJ/h 0 0 852 1,794

Energy Consumption Summary

Natural Gas - GTG GJ/h 1,547 2,090 1,547 2,090

HRSG GJ/h 672 1,074 672 1,074

Space Heating GJ/h 604 949 366 414

Boilers GJ/h 1,407 1,473 583 388

Total GJ/h 4,231 5,586 3,169 3,966

Energy Intensity GJ/bbl 0.51 0.67 0.38 0.48

Electricity Generated MWh/d 3,044 4,198 3,044 4,198

GHG Emissions Summary

Stationary Combustion tCO2e/d 4,974 7,364 4,057 5,079

Fugitive Mine kg CO2e/m2/d 0.0001 – 0.0150 0.000007 – 0.0355 0.0001 – 0.0150 0.000007 – 0.0355

Fugitive Pond kg CO2e/m2/d 0.0007 – 0.0201 0.0007 – 0.0201 0.0119 – 0.8054 0.0119 – 0.8054 Total Cogen Emissions (Gt) tCO2e/d 2,698 4,171 2,842 4,051

DH tCO2e/d 2,158 3,337 2,273 3,241

DE tCO2e/d 540 834 568 810

CO2 : Bitumen tCO2e/bbl 0.029 0.043 0.024 0.031


Conclusion


5.0 CONCLUSION

Stantec completed four material and energy flow diagrams for oil sands surface mining and extraction PFT and NFT reference facilities for both high and low grade conditions with a production of 200,000 bbl/d of bitumen. These diagrams provide a basis of process information intended to help prospective technology developers evaluate any GHG reduction opportunities and water and heat recovery possibilities. Process simulation models and Excel spreadsheet calculators were used as a key tool to achieve the natural gas consumption and the quantity of the boiler feed water required to produce sufficient energy and steam for the ore preparation and extraction processes, which was provided by CanmetENERGY. The GHG emissions from the reference facility were also calculated for each of the processes.


Appendix A Material and Energy Balance Diagrams

APPENDIX


Appendix A Material and Energy Balance Diagrams

Appendix A MATERIAL AND ENERGY BALANCE DIAGRAMS

COSIA Mining & Extraction High Grade - Paraffinic Froth Treatment - Material and Energy FlowOre Grade wt% Legend

Fine Contents wt% Bitumen Steam Flue gas TailingWaste to Ore wt% Water Natural Gas Solvent Air

AbbreviationsBFW Boiler Feed Water PSC Primary Separation Cell

Ore Preparation: Conditioning, Crushing and Conveying CW Cooling Water PW Process WaterCWR Cooling Water Return SG Specific Gravity

Mine Face T/h Crusher Conveyor Feed Rotary Breaker FSU Froth Settling Unit SRU Solvent Recovery UnitTruck and Shovel 5 °C System 50°C Rejects GTG Gas Turbine Generator TDS Total Dissolved SolidsBitumen 12 wt% Bitumen 3 wt% HHV Higher Heating Value TOC Total organic carbon Water 3 wt% Water 6 wt% HRSG Heat Recovery Steam Generator TSRU Tailing Solvent Solids 85 wt% Solids 91 wt% LPS Low Pressure Steam Recovery Unit

Hot Process Water 80 °C T/h MPS Medium Pressure Steam26 T/h Gland Cooling Water 25 °C T/h T/h Breaker Rejects

Warm Dilution Water 45 °C T/h Hydrotransport Pump T/h Bitumen Recovery SummarySG 1.5-1.6 Ore Preparation

Primary Extraction 50 °C Vent to atmosphere Primary ExtractionT/h Froth Treatment (without rejected asphaltenes)

Caustic Deaerating Steam 72 T/h Deaerator 47 °C 2419 T/h oC Total Bitumen RecoveryNaOH 203 GJ/h Bitumen 61 wt% Flotation Froth Asphaltenes Rejection

Deaerated Froth 77 °C Water 28.1 wt% Middlings Total Bitumen Recovery (with rejected asphaltenes)T/h Solids 11.8 wt%

Bitumen 60 wt% Water Summary (T/H)Water 28.4 wt% Middlings Displacement Cooling Water

Cooling Water T/h Solids 11.6 wt% Heated WaterPSC Tailing Reclaimed Water

T/h Raw WaterBitumen 0.3 wt% BFW

Solvent Feed/MPS Deaerated Froth Pump PSC Tailing Pump Water 60 wt% Boiler BlowdownExchanger Duty Solids 40 wt% Make-Up Water321 GJ/h 133 T/h Secondary Extraction- Froth Treatment 332 T/h 1,202 GJ/h Condensate Return

225 oC SRU/MPS Exchanger Duty 225 oC20 oC Solvent 2,259 T/h 800 GJ/h Solvent - Bitumen to SRU T/h Energy Output Summary

4 T/h Makeup 77 oC Bitumen 38 wt% Cogen GTG ElectricityGland Cooling Water 61 T/h Solvent to Bitumen 1.65 wt/wt HRSG Steam

99 oC Water 0.03 wt% Compressor 12 Cogen Losses133 T/h Bitumen 10.4 wt% 33 T/h Subtotal - Cogen

Solvent Make up 99 oC Water 62 wt% 93 GJ/h Boilers Steam20 °C Solids 23 wt% 332 T/h Boiler Losses

99 oC Cooler Duty 22 GJ/h Subtotal - BoilersRecovered Solvent Tailing to TSRU T/h Total

T/h SRU Recovered Water 34 T/hSolvent Loss : Bitumen Gland Cooling Water 143 T/h 80 oC Flue Gas - Based on Stochiometric Combustion

0.3 % vol./vol. Natural Gas HHVCooler Duty Excess air @ 13% O2 (from Cogen Facility)

39 T/h 132 GJ/h 103 oC Excess O2 (from Cogen Facility)110 GJ/h Cogen Flue Gas

CO2 in Flue Gas from Cogen51 T/h 38oC H2O in Flue Gas from Cogen

T/h Boiler Flue Gas466 T/h TSRU Tailing Pump CO2 in Flue Gas from Boilers99 oC TSRU Tailing T/h H2O in Flue Gas from Boilers

Bitumen 7 % bbl/sd Flue Gas Temperature - Acid Dew Point LimitWater 70 % Bitumen 99.9 % Flue Gas - Max. without Economizer

Tailing Reclaimed Water Solids 21 % Asphaltene 12.0 %T/h 40 oC Solids + Water 0.1 % Exchanger & Cooler

83 % Process Water Recycled Asphaltene Rejection 7.6 % Process Water / Cooling Water25 oC Process Water / Condensate

Process Water / LPS4,396 T/h SRU Feed / MPS

Solvent Feed / MPSCooler x 3

Utilities CW (Cold) CW (Warm) PW/LPS Heat Rejection30 °C 60 °C Condensate Exchanger Duty

186 °C 768 GJ/h T/h Energy Consumption SummaryMake-up Water T/h Raw Water Pond T/h Recycled Water Pond T/h 49 °C 56 °C 80 °C Hot Water Tank °C Natural Gas GTG

25 °C Water treatment 25oC 25oC 80oC HRSGMake-up Water 165 T/h Recovered T/h PW/CW Exchanger Duty PW/Condensate Building Heating and Flare

mg/L TDS 25 oC Condensate °C GJ/h Exchanger Duty Warm Water Tank Boilersmg/L Silica 843 T/h 378 T/h 208 GJ/h 144 T/h 45oC Energy Intensity (GJ per bbl of bitumen produced)mg/L Hardness 80 oC 57 °C 407 GJ/h Electricity Generatedmg/L TOC Electricity Cogen Energy Output Stripping Steam HRSG Flue Gas

Fresh Water : Bitumen 127 MW Electricity 457 GJ/h Electricity 1,964 T/h GHG Emissions Summaryvol./vol. 457 GJ/h 1,321 GJ/h BFW Preheating and Steam Processing Heating 454 GJ/h Stationary Combustion & Flaring t CO2e/d

T/h 80% Efficiency 466 T/h m3/h act. Fugitive Mine - kg CO2e/m2/doC GTG T/h Duct Burner T/h HRSG 524 T/h 988 T/h MPS GJ/h 3.7 % vol. CO2 Fugitive Pond - kg CO2e/m2/dmg/L TDS (12.1 GJ/h) 2 Units 2 Units GJ/h 2,788 GJ/h 225oC, 2,100 kPag 76.2 % vol. N2 Total Cogen Emissions (Gt) t CO2e/dmg/L Silica GTG Duct Burner 524 T/h 13 % vol. O2 Deemed emissions from Heat by Cogen (DH) t CO2e/dmg/L Hardness GJ/h HHV 1,340 T/h GJ/h HHV 157 GJ/h 7.2 % H2O Deemed emissions from Electricity by Cogen (DE) t CO2e/d

mg/L TOC m3/h m3/h LPS Utility Steam 143 oC378 T/h LPS Material and Energy Balance for an Oil Sands Surface Mining

Space Heating Boilers 464 T/h GJ/h 210oC, 1,390 kPag Aux.Boiler Flue Gas and Bitumen Extraction Reference FacilityNatural Gas Required Purge Gas to Flare GJ/h 485 T/h GJ/h 520 T/h, 185 GJ/h, 553,728 m3/h actual Case: Paraffinic - High Grade Revision: NA

Natural Gas GJ/h HHV GJ/h HHV m3/h 146 GJ/h 8.7% vol. CO2, 72.3% vol N2, 2.2% vol. O2, 16.8% H2O Owner: COSIA Date:25 °C m3/h actual 87 % Efficiency Auxilary Boiler 121oC Material & Energy Balance

unit Boiler Blowdown High Temperature Extraction, High Grade, Summer ConditionAir 212 T/h 582 T/h T/h By B. Thitakamol (Stantec)

25 °C T/h 493 T/h GJ/h @ 345 kPag Q. Zhuang (CanmetENERGY/NRCAN)2,627

13

Output (GJ/h)

6,059

0

165

7

515

3.4 MW from Compressor

21

1,964

35,173

2,162,595

4,231105,769

6

1,407604

755

34

1,067

1,315

2,645

BFW

6,217

843

203.9

2,645

6

6,059

21

1,478

2.04

14,051

100972

25

1,54738,678

67216,812

1,369

2,480

2,791

4571,321453

2,2311,222185

7,522

1,4073,638

40 MJ/m3

1,547672

2,2311,407

%

2,255

244 4414,396 18,888

2,443

5,769

26,634

3,546

1,217

2,204

200,000

14,051

1,382

665

Tailing Pond

1211.94.3

13,142

5,918

Input (GJ/h)

179 %

99.0%

7.6%

1,4073,638

85.1%

94.6%98.4%92.2%

10,314

2,480

Process Water

2,163 e3m3/h

57

1,310

5,91880

9% vol.%17% vol.%121 °C

4% vol.%7% vol.%554 e3m3/h

768800

601

GJ/h e3m3/d

274 °C

Duty (GJ/h)755208

1,407 844

3211,356

Project:

25-Feb-20

0.0007

0.51 GJ/bbl

1,547 928672 403604 363

0.00014,974

2,6982,158540

3,044 MWH/d

0.01500.0201

PSC

Flotation & Cyclone

FSU 70-90 °C

Bitumen

TSRU 90 °C

SRU 215 °C

CWCWR

CWCWR

CW

CWR

80oC

, 1604 T/h

This is based on assummed open-pit mine that produces 200,000 barrels per day. While representative, it is not based on any one facility.Recovery and solvent loss is based on Alberta Energy Regulator requirements.

COSIA Mining & Extraction Low Grade - Paraffinic Froth Treatment - Material and Energy FlowOre Grade wt% l Legend

Fine Contents wt% Bitumen Steam Flue gas TailingWaste to Ore wt% Water Natural Gas Solvent Air

AbbreviationsBFW Boiler Feed Water PSC Primary Separation Cel

Ore Preparation: Conditioning, Crushing and Conveying CW Cooling Water PW Process WaterCWR Cooling Water Return SG Specific Gravity

Mine Face T/h Crusher Conveyor Feed Rotary Breaker FSU Froth Settling Unit SRU Solvent Recovery UnitTruck and Shovel -3 °C System 50°C Rejects GTG Gas Turbine Generator TDS Total Dissolved SolidsBitumen 8.6 wt% Bitumen 3 wt% HHV Higher Heating Value TOC Total organic carbon Water 6.4 wt% Water 4 wt% HRSG Heat Recovery Steam Generator TSRU Tailing Solvent Solids 85 wt% Solids 92.5 wt% LPS Low Pressure Steam Recovery Unit

Hot Process Water 80 °C T/h MPS Medium Pressure Steam38 T/h Gland Cooling Water 2 °C T/h 928 T/h Breaker Rejects

Warm Dilution Water 45 °C T/h Hydrotransport Pump T/h Bitumen Recovery SummarySG 1.5-1.6 Ore Preparation

Primary Extraction 50 °C Vent to atmosphere Primary ExtractionT/h Froth Treatment (without rejected asphaltenes)

Caustic Deaerating Steam 72 T/h Deaerator 40-50 °C oC Total Bitumen RecoveryNaOH 204 GJ/h Flotation Froth Asphaltenes Rejection

Deaerated Froth 77 °C Middlings Total Bitumen Recovery (with rejected asphaltenes)T/h

Bitumen 53 wt% Water Summary (T/H)Water 35 wt% Middlings Displacement Cooling Water

Cooling Water T/h Solids 12 wt% Heated WaterPSC Tailing Reclaimed Water

T/h Raw WaterBitumen 0.38 wt% BFW

Solvent Feed/MPS Deaerated Froth Pump PSC Tailing Pump Water 54 wt% Boiler BlowdownExchanger Duty Solids 46 wt% Make-Up Water415 GJ/h 172 T/h Secondary Extraction- Froth Treatment 337 T/h Cooler Duty 1,228 GJ/h Condensate Return

225 oC SRU/MPS Exchanger Duty 225 oC2 oC Solvent 2,302 T/h 811 GJ/h Solvent - Bitumen to SRU T/h Energy Output Summary

3.5 T/h Makeup 77 oC Bitumen 33 wt% Cogen GTG ElectricityGland Cooling Water 72 T/h Solvent to Bitumen 1.65 wt/wt HRSG Steam

Compressor 16 Cogen Losses172 T/h Bitumen 8.2 wt% 32 T/h Subtotal - Cogen

Solvent Make up 99 oC Water 67 wt% 91 GJ/h Boilers Steam2 °C Solids 22 wt% 337 T/h Boiler Losses

99 oC Cooler Duty 21 GJ/h Subtotal - BoilersRecovered Solvent Tailing to TSRU T/h Total

T/h SRU Recovered Water 33 T/hSolvent Loss : Bitumen Gland Cooling Water 168 T/h 80 oC Flue Gas - Based on Stochiometric Combustion

0.3 % vol./vol. Natural Gas HHVCooler Duty Excess air @ 13% O2 (from Cogen Facility)

44 T/h 117 GJ/h 100 oC Excess O2 (from Cogen Facility)125 GJ/h Cogen Flue Gas

CO2 in Flue Gas from Cogen47 T/h 38oC H2O in Flue Gas from Cogen

T/h Boiler Flue Gas509 T/h TSRU Tailing Pump CO2 in Flue Gas from Boilers99 oC TSRU Tailing T/h H2O in Flue Gas from Boilers

Bitumen 7 % bbl/sd Flue Gas Temperature - Acid Dew Point LimitWater 70 % Bitumen 99.9 % Flue Gas - Max. without Economizer

Tailing Reclaimed Water Solids 21 % Asphaltene 12.0 %T/h 40 oC Solids + Water 0.04 % Exchanger & Cooler

81 % Process Water Recycled Asphaltene Rejection 7.7 % Process Water / Cooling Water2 oC Process Water / Condensate

Process Water / LPS1,716 T/h SRU Feed / MPS

Solvent Feed / MPSCooler x 3

Utilities CW (Cold) CW (Warm) PW/LPST/h 30 °C 60 °C Condensate Exchanger Duty

186 °C 1,280 GJ/h T/h Energy Consumption SummaryMake-up Water T/h Raw Water Pond T/h Recycled Water Pond T/h 38 °C 47 °C 80 °C Hot Water Tank °C Natural Gas GTG

2 °C Water treatment 2oC 2oC 80oC HRSGMake-up Water 198 T/h T/h PW/CW Exchanger Duty PW/Condensate 629 T/h Building Heating and Flare

mg/L TDS 2 oC °C 1,365 GJ/h Exchanger Duty Warm Water Tank Boilersmg/L Silica Treated Water/ LPS 629 T/h 357 GJ/h 148 T/h 45oC Energy Intensity (GJ per bbl of bitumen produced)mg/L Hardness Exchanger Duty 8 T/h 53 °C 419 GJ/h Electricity Generatedmg/L TOC 19 GJ/h 210 oC Electricity Cogen Energy Output Stripping Steam HRSG Flue Gas

Fresh Water : Bitumen 71 oC 25 oC Recovered Condensate 175 MW Electricity 630 GJ/h Electricity 3,036 T/h GHG Emissions Summaryvol./vol. 74 oC 1,139 T/h 630 GJ/h 2,044 GJ/h BFW Preheating and Steam Processing Heating 506 GJ/h Stationary Combustion & Flaring t CO2e/d

85% Efficiency T/h m3/h act. Fugitive Mine - kg CO2e/m2/dGTG T/h Duct Burner T/h HRSG 804 T/h 1,294 T/h MPS GJ/h 3.7 % vol. CO2 Fugitive Pond - kg CO2e/m2/d

T/h (16.5 GJ/h) 2 Units 2 Units GJ/h 3,656 GJ/h 225oC, 2,100 kPag 76.2 % vol. N2 Total Cogen Emissions (Gt) t CO2e/doC GTG Duct Burner 804 T/h 13 % vol. O2 Deemed emissions from Heat by Cogen (DH) t CO2e/dmg/L TDS GJ/h HHV 1,963 T/h GJ/h HHV 226 GJ/h 7.2 % H2O Deemed emissions from Electricity by Cogen (DE) t CO2e/d

mg/L Silica m3/h m3/h LPS Utility Steam 143 oCmg/L Hardness T/h LPS Material and Energy Balance for an Oil Sands Surface Mining mg/L TOC Space Heating Boilers 490 T/h GJ/h 210oC, 1,390 kPag Aux.Boiler Flue Gas and Bitumen Extraction Reference Facility

Natural Gas Required Purge Gas to Flare GJ/h 540 T/h GJ/h 590 T/h, 101 GJ/h, 628,501 m3/h actual Case: Paraffinic - Low Grade Revision: NANatural Gas GJ/h HHV GJ/h HHV m3/h 151 GJ/h 8.7% vol. CO2, 72.3% vol N2, 2.2% vol. O2, 16.8% H2O Owner: COSIA Date:

2 °C m3/h actual m3/h actual 93 % Efficiency Auxilary Boiler 121oC Material & Energy Balanceunit Boiler Blowdown High Temperature Extraction, Low Grade, Winter Condition

Air 361 T/h T/h T/h By B. Thitakamol (Stantec)2 °C T/h 560 T/h GJ/h @ 345 kPag Q. Zhuang (CanmetENERGY/NRCAN)3,892

65

1,366

Tailing Pond

6,059

0

198

7

515


Process Water

BFW

7,604

1,139

203.9

2,507

6

6,059

50

2,270

6

1,473949

23,725

2.25

15,206

34

2,309

1,344 67

2

2,09052,257

1,074 26,838

2,298

1,473

1,4734,653

9% vol.%17% vol.%121

98.2%

7.7%

2,507

82.3%

92.3%98.4%89.1%

2,309

769

6302,044506

3,1801,372101

9,142

9,911

1,4734,653

40 MJ/m3

2,0901,074

3,180

7,017

32,406

3,594

1,551

2,251

200,000

15,206

1,751

920.01.5

18,765

8,195

137

1,386

8,19580

3471,716 26,417

2,773

7

50

2,006 3,036

36,815

3,342,767

5,585139,635

Project:

2,090 1,2541,074 644949 525

811

GJ/h e3m3/d

415

0.000007

%3,343 e3m3/h4% vol.%7% vol.%

0.03550.0007 0.0201

274 °C

Duty (GJ/h)1,365357

°C

1,280

Output (GJ/h)Input (GJ/h)

1,799 637

1,438 509

1,008

7,604

25-Feb-20

7,364

4,1713,337834

4,198 MWH/d

1,473 8840.67 GJ/bbl

629 e3m3/h

180 %13

PSC

Flotation & Cyclone

FSU 70-90 °C

Bitumen

TSRU 90 °C

SRU 215 °C

CWCWR

CWCWR

CW

CWR

80oC

, 947 T/h


COSIA Mining & Extraction High Grade - Naphthenic Froth Treatment - Material and Energy FlowOre Grade wt% Legend

Fine Contents wt% Bitumen Steam Flue gas Tailing VentWaste to Ore wt% Water Natural Gas Solvent Air

AbbreviationsBFW Boiler Feed Water MPS Medium Pressure Steam

Ore Preparation: Conditioning, Crushing and Conveying CW Cooling Water PSC Primary Separation CellCWR Cooling Water Return PW Process Water

Mine Face T/h Crusher Conveyor Feed Rotary Breaker GTG Gas Turbine Generator NRU Naphtha Recovery UnitTruck and Shovel 4 °C System 50°C Rejects HHV Higher Heating Value TDS Total Dissolved SolidsBitumen 12 wt% Bitumen 3.6 wt% HRSG Heat Recovery Steam Generator TOC Total organic carbon Water 3 wt% Water 5.6 wt% LPS Low Pressure SteamSolids 85.6 wt% Solids 91 wt%

Hot Process Water 80 °C T/h Bitumen Recovery Summary24 T/h Gland Cooling Water 10 °C T/h T/h Breaker Rejects Ore Preparation

Warm Dilution Water 45 °C T/h Hydrotransport Pump T/h Primary ExtractionFroth Treatment (without rejected asphaltenes)

Primary Extraction 50 °C Vent to atmosphere Total Bitumen RecoveryT/h Asphaltenes Rejection

Caustic Stripping Steam 65 T/h Deaerator 40 - 50 °C T/h oC Total Bitumen Recovery (with rejected asphaltenes)NaOH 184 GJ/h Bitumen 61 wt% Flotation Froth

Deaerated Froth 77 °C Water 28.1 wt% Middlings Water Summary (T/H)T/h Solids 11.8 wt% Cooling Water

Bitumen 58 wt% Heated WaterWater 32 wt% Middlings Displacement Reclaimed Water

Cooling Water T/h Solids 10 wt% Raw Water°C 41 GJ/h PSC Tailing BFW

T/h Boiler Blowdown17 T/h 17 T/h Bitumen 0.1 wt% Make-Up Water

Deaerated Froth Pump 99 oC 225 oC PSC Tailing Pump Water 58 wt% Condensate ReturnDiluent Feed/MPS Solids 42 wt%Exchanger Duty 313 T/h Secondary Extraction- Froth Treatment Energy Output Summary Input (GJ/h) Output (GJ/h)

754 GJ/h 225 oC Cogen GTG Electricity885 T/h Makeup Diluent 955 T/h T/h HRSG Steam

wt% Bitumen Centrifuge Compressor 12 Cogen LossesWarm Water 19 T/h wt% Water wt% Bitumen Subtotal - Cogen

45 °C wt% Solids wt% Water Boilers Steamwt% Solvent wt% Solids Boiler Losses

Diluent 313 T/h wt% Solvent Cooler Duty Subtotal - Boilers48 °C 99 oC T/h 159 GJ/h Total

Diluent : Bitumen 0.7 wt / wt wt% BitumenDiluent Loss : Bitumen 0.3 vol./vol. wt% Water Flue Gas - Based on Stochiometric Combustion

wt% Solids Natural Gas HHVwt% Diluent Excess air @ 13% O2 (from Cogen Facility)

Cooler Duty T/h Excess O2 (from Cogen Facility)70 T/h 11 GJ/h 2 wt% Bitumen Cogen Flue Gas

Stripping Steam 40 T/h 70 wt% Water CO2 in Flue Gas from Cogen113 GJ/h 21 wt% Solids H2O in Flue Gas from Cogen

7 wt% Diluent Boiler Flue GasCooler Duty NRU Tailing CO2 in Flue Gas from Boilers

330 T/h 202 GJ/h T/h H2O in Flue Gas from Boilers99 oC NRU Tailing Pump wt% Bitumen Flue Gas Temperature - Acid Dew Point Limit

wt% Water Flue Gas - Max. without Economizerwt% Solids T/h Bitumenwt% Diluent bbl Bitumen Exchanger & Cooler

Tailing Reclaimed Water 40 oC T/h Diluent Process Water / Cooling WaterT/h 0.63 wt / wt Diluent : Bitumen Process Water / Condensate

85 % Process Water Recycled 0.88 vol / vol Diluent : Bitumen Process Water / LPS10 oC 17 wt% Asphaltene in Bitumen Diluent Feed / MPS

2.5 wt% Solids + Water HeaterT/h Cooler x 3

Other Process UseUtilities CW (Cold) CW (Warm) PW/LPS

30 °C 60 °C Condensate Exchanger Duty Energy Consumption Summary186 °C 613 GJ/h T/h Natural Gas GTG

Make-up Water T/h Raw Water Pond T/h Recycled Water Pond T/h 53 °C 59 °C 80 °C Hot Water Tank °C HRSG10 °C Water treatment 10oC 10oC 80oC Building Heating and Flare

Make-up Water 125 T/h Recovered T/h PW/CW Exchanger Duty PW/Condensate Boilersmg/L TDS 10 oC Condensate °C GJ/h Exchanger Duty Warm Water Tank Energy Intensity (GJ per bbl of bitumen produced)mg/L Silica 632 T/h 301 T/h 160 GJ/h 105 T/h 45oC Electricity Generatedmg/L Hardness 81 oC 57 °C 297 GJ/hmg/L TOC Electricity Cogen Energy Output Stripping Steam HRSG Flue Gas GHG Emissions Summary

Fresh Water : Bitumen 127 MW Electricity 457 GJ/h Electricity 2,069 T/h Stationary Combustion & Flaring t CO2e/dvol./vol. 457 GJ/h 1,383 GJ/h BFW Preheating and Steam Processing Heating 391 GJ/h Fugitive Mine - kg CO2e/m2/d

T/h 82% Efficiency 330 T/h m3/h act. Fugitive Pond - kg CO2e/m2/doC GTG T/h Duct Burner T/h HRSG 547 T/h 737 T/h MPS 933 GJ/h 3.7 % vol. CO2 Total Cogen Emissions (Gt) t CO2e/dmg/L TDS (12.1 GJ/h) 2 Units 2 Units GJ/h 2,080 GJ/h 225oC, 2,100 kPag 76.2 % vol. N2 Deemed emissions from Heat by Cogen (DH) t CO2e/dmg/L Silica GTG Duct Burner 547 T/h 13 % vol. O2 Deemed emissions from Electricity by Cogen (DE) t CO2e/dmg/L Hardness GJ/h HHV 1,411 T/h GJ/h HHV 161 GJ/h 7.2 % H2O

mg/L TOC m3/h m3/h LPS Utility Steam 143 oC Material and Energy Balance for an Oil Sands Surface Mining 301 T/h LPS and Bitumen Extraction Reference Facility

Space Heating Boilers 190 T/h 851 GJ/h 210oC, 1,390 kPag Aux.Boiler Flue Gas Case: Naphthenic - High Grade Revision: NANatural Gas Required Purge Gas to Flare GJ/h 210 T/h 536 GJ/h 277 T/h, 53 GJ/h, 241,733 m3/h actual Owner: COSIA Date:

Natural Gas GJ/h HHV GJ/h HHV m3/h 62 GJ/h 8.7% vol. CO2, 72.3% vol N2, 2.2% vol. O2, 16.8% H2O Material & Energy Balance10 °C m3/h actual 91 % Efficiency Auxilary Boiler 121oC High Temperature Extraction, High Grade, Summer Condition

unit Boiler Blowdown By B. Thitakamol (Stantec)Air 135 T/h 613 T/h T/h Q. Zhuang (CanmetENERGY/NRCAN)

10 °C T/h 215 T/h GJ/h @ 345 kPag

65

Heater Duty

Tailing Pond

852

10

2,375

2,419

1,224

25-Feb-20

4,057

2,8422,273568

3,044 MWH/d

413,533

4% vol.%7% vol.%242 e3m3/h

1,547 928

Project:

672

55

5,04580

9% vol.%17% vol.%121 °C

613754

372

GJ/h e3m3/d

274 °C

Duty (GJ/h)1,224160

583

2,393

138

58

179 %13 %

2,278 e3m3/h

28381222

2 583

5832,814

39.1

125

2,231

1211.7

4.3

12,187

5,045227 412

3,514 17,072

5,372

23,623

1,977

200,000

12,304

1,339

881

1,354591.50

1,019 2

76 22

0.4

98.9%

0.0%

1,998

95.2%

98.0%98.2%95.2%

1,873

1,771

4571,383391

2,23153053

6,807

8,578

583

6

2,814

40 MJ/m3

1,547672

20

1,442 2,069

14,576

2,278,235

3,16979,216

6

583366

515

3.4 MW from C

Process Water

BFW

5,599

6321,998

6,059

20

1,544

12,304

34

1,873

75770

1,049

38,678672

16,812

403366 220

6,059

0

10

1,547

7203.9

6

1.80 0.0001 0.01500.0119 0.8054

3500.38 GJ/bbl

PSC

Flotation & Cyclone

Inclined Plate Separator 84°C

Diluted Bitumen

NRU 99 °C

Centrifuge 84 °C

CWCWR

CWCWR

80oC

, 1762 T/h

928T/h

CWCWR


COSIA Mining & Extraction Low Grade - Naphthenic Froth Treatment - Material and Energy FlowOre Grade wt% Legend

Fine Contents wt% Bitumen Steam Flue gas Tailing VentWaste to Ore wt% Water Natural Gas Solvent Air

AbbreviationsBFW Boiler Feed Water MSC Medium Pressure Steam

Ore Preparation: Conditioning, Crushing and Conveying CW Cooling Water PSC Primary Separation CellCWR Cooling Water Return PW Process Water

Mine Face T/h Crusher Conveyor Feed Rotary Breaker GTG Gas Turbine Generator NRU Naphtha Recovery UnitTruck and Shovel 1 °C System 50°C Rejects HHV Higher Heating Value TDS Total Dissolved SolidsBitumen 9 wt% Bitumen 3 wt% HRSG Heat Recovery Steam Generator TOC Total organic carbon Water 6 wt% Water 4 wt% LPS Low Pressure SteamSolids 85 wt% Solids 92 wt%

Hot Process Water 80 °C T/h Bitumen Recovery Summary35 T/h Gland Cooling Water 10 °C T/h T/h Breaker Rejects Ore Preparation

Warm Dilution Water 45 °C T/h Hydrotransport Pump T/h Primary ExtractionFroth Treatment (without rejected asphaltenes)

Primary Extraction 50 °C Vent to atmosphere Total Bitumen RecoveryT/h Asphaltenes Rejection

Caustic Stripping Steam 65 T/h Deaerator 40 - 50 °C T/h oC Total Bitumen Recovery (with rejected asphaltenes)NaOH 184 GJ/h Bitumen 54 wt% Flotation Froth

Deaerated Froth 77 °C Water 32 wt% Middlings Water Summary (T/H)T/h Solids 12 wt% Cooling Water

Bitumen 54 wt% Heated WaterWater 32 wt% Middlings Displacement Reclaimed Water

Cooling Water T/h Solids 12 wt% Raw WaterHeater Duty 43 GJ/h PSC Tailing BFW

T/h Boiler Blowdown18 T/h 18 T/h Bitumen 0.32 wt% Make-Up Water

Deaerated Froth Pump 99 oC 225 oC PSC Tailing Pump Water 64 wt% Condensate ReturnDiluent Feed/MPS Solids 39 wt%Exchanger Duty 313 T/h Secondary Extraction- Froth Treatment Energy Output Summary

754 GJ/h 225 oC Cogen GTG Electricity885 T/h Markup Diluent 955 T/h T/h HRSG Steam

wt% Bitumen Centrifuge Compressor 16 Cogen LossesWarm Water 19 T/h wt% Water wt% Bitumen Subtotal - Cogen

wt% Solids wt% Water Boilers Steamwt% Solvent wt% Solids Boiler Losses

Diluent 313 T/h wt% Solvent Cooler Duty Subtotal - Boilers48 °C 99 oC T/h 159 GJ/h Total

Diluent : Bitumen 0.7 wt / wt wt% BitumenDiluent Loss : Bitumen 0.3 vol./vol. wt% Water Flue Gas - Based on Stochiometric Combustion

wt% Solids Natural Gas HHVwt% Diluent Excess air @ 13% O2 (from Cogen Facility)

Cooler Duty Excess O2 (from Cogen Facility)70 T/h 11 GJ/h Cogen Flue Gas

Stripping Steam 40 T/h T/h CO2 in Flue Gas from Cogen113 GJ/h 2 wt% Bitumen H2O in Flue Gas from Cogen

66 wt% Water Boiler Flue GasCooler Duty NRU Tailing 25 wt% Solids CO2 in Flue Gas from Boilers

331 T/h 226 GJ/h T/h 6 wt% Diluent H2O in Flue Gas from Boilers99 oC NRU Tailing Pump wt% Bitumen Flue Gas Temperature - Acid Dew Point Limit

wt% Water Flue Gas - Max. without Economizerwt% Solids T/h Bitumenwt% Diluent bbl Bitumen Exchanger & Cooler

Tailing Reclaimed Water 40 oC T/h Diluent Process Water / Cooling WaterT/h 0.63 wt / wt Diluent : Bitumen Process Water / Condensate

85 % Process Water Recycled 0.88 vol / vol Diluent : Bitumen Process Water / LPS10 oC 17 wt% Asphaltene in Bitumen Diluent Feed / MPS

2.5 wt% Solids + Water HeaterT/h Cooler x 3

Other Process UseUtilities CW (Cold) CW (Warm) PW/LPS

30 °C 60 °C Condensate Exchanger Duty Energy Consumption Summary186 °C 937 GJ/h T/h Natural Gas GTG

Make-up Water T/h Raw Water Pond T/h Recycled Water Pond T/h 53 °C 59 °C 80 °C Hot Water Tank °C HRSG10 °C Water treatment 10oC 10oC 80oC Building Heating and Flare

Make-up Water 133 T/h Recovered T/h PW/CW Exchanger Duty PW/Condensate Boilersmg/L TDS 10 oC Condensate °C 2190 GJ/h Exchanger Duty Warm Water Tank Energy Intensity (GJ per bbl of bitumen produced)mg/L Silica 792 T/h 461 T/h 244 GJ/h 105 T/h 45oC Electricity Generatedmg/L Hardness 78 oC 57 °C 297 GJ/hmg/L TOC Electricity Cogen Energy Output Stripping Steam HRSG Flue Gas GHG Emissions Summary

Fresh Water : Bitumen 175 MW Electricity 630 GJ/h Electricity T/h Stationary Combustion & Flaring t CO2e/dvol./vol. 630 GJ/h GJ/h BFW Preheating and Steam Processing Heating 557 GJ/h Fugitive Mine - kg CO2e/m2/d

T/h 82% Efficiency 331 T/h m3/h act. Fugitive Pond - kg CO2e/m2/doC GTG T/h Duct Burner T/h HRSG 786 T/h 897 T/h MPS 935 GJ/h 3.7 % vol. CO2 Total Cogen Emissions (Gt) t CO2e/dmg/L TDS (16.4 GJ/h) 2 Units 2 Units GJ/h 2,534 GJ/h 225oC, 2,100 kPag 76.2 % vol. N2 Deemed emissions from Heat by Cogen (DH) t CO2e/dmg/L Silica GTG Duct Burner 786 T/h 13 % vol. O2 Deemed emissions from Electricity by Cogen (DE) t CO2e/dmg/L Hardness GJ/h HHV 1,907 T/h GJ/h HHV 225 GJ/h 7.2 % H2O

mg/L TOC m3/h m3/h LPS Utility Steam 143 oC Material and Energy Balance for an Oil Sands Surface Mining 461 T/h LPS and Bitumen Extraction Reference Facility

Space Heating Boilers 111 T/h GJ/h 210oC, 1,390 kPag Aux.Boiler Flue Gas Case: Naphthenic - Low Grade Revision: NANatural Gas Required Purge Gas to Flare GJ/h 139 T/h 316 GJ/h 151 T/h, 36 GJ/h, 161,074 m3/h actual Owner: COSIA Date:

Natural Gas GJ/h HHV GJ/h HHV m3/h 40 GJ/h 8.7% vol. CO2, 72.3% vol N2, 2.2% vol. O2, 16.8% H2O Material & Energy Balance10 °C m3/h actual 91 % Efficiency Auxilary Boiler 121oC High Temperature Extraction, Low Grade, Winter Condition

unit Boiler Blowdown By B. Thitakamol (Stantec)Air 153 T/h 979 T/h T/h Q. Zhuang (CanmetENERGY/NRCAN)

10 °C T/h 144 T/h GJ/h @ 345 kPag

2,090 1,2541,074 644414 363

6,059

0

10

2,090

7203.9

6

2.70 0.000007 0.03550.0119 0.8054

515


Process Water

BFW

6,849

7921,425

6,059

28

2,218

20,292

34

1,292

92568

52,2571,074

26,838

3,180

28

1,949 2,950

9,712

3,247,378

3,96699,157

6

388414

98.9%

0.0%

1,425

95.2%

98.0%98.2%95.2%

1,292

3,226

6301,993557

3,18035336

11,509

14,735

388

6

3,569

40 MJ/m3

2,0901,074

6,526

35,734

2,099

200,000

20,292

1,339

881

1,354591.50

2 71 26

0.3

1,141

920

1.2

17,451

8,271323 863

6,445 25,217

2330.48

2,512

138

58

179 %13 %

3,247 e3m3/h

27381520

3 388

3883,569

39.1

133

Input (GJ/h) Output (GJ/h)

vol.%161 e3m3/h

GJ/bbl

77

8,27180

9% vol.%17% vol.%121 °C

937754

396

GJ/h e3m3/d

274 °C

Duty (GJ/h)2,190244

388

3,183

1,794

65

1,302

Tailing Pond

25-Feb-19

Project:

2,453

1,170

6,464

2,9501,993

5,079

4,0513,241810

4,198 MWH/d

43

4% vol.%7%

PSC

Flotation & Cyclone

Inclined Plate Separator 84°C

Diluted Bitumen

NRU 99 °C

Centrifuge 84 °C

CWCWR

CWCWR

80oC

, 3,238 T/h

928T/h

CWCWR


Documents

Material and Energy Balance for an Oil Sands Surface Mining and Bitumen Extraction ... · 2020. 7. 7. · Guidance for Completing Specified Gas Compliance Reports (Version 7.0, January