In Situ Oil Sands Technology Trends

STUDY NO. 193 DECEMBER 2020

IN SITU OIL SANDS TECHNOLOGY TRENDS

3512 - 33 Street NW, #150, Calgary, AB T2L 2A6 350 Sparks Street, #805, Ottawa, ON K1R 7S8

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@ceri_canada

Canadian Energy Research Institute

In Situ Oil Sands Technology Trends

Authors: Evar Umeozor, Madie Zamzadeh, Dinara Millington

Recommended Citation (Author-date style): Umeozor, Evar, Madie Zamzadeh, and Dinara Millington. 2021. “In Situ Oil Sands Technology Trends.” Study No. 193 Calgary, AB: Canadian Energy Research Institute. https://ceri.ca/assets/files/Study_193_Full_Report.pdf

Recommended Citation (Numbered style): E. Umeozor, M. Zamzadeh and D. Millington, “In Situ Oil Sands Technology Trends,” Canadian Energy Research Institute, Calgary, AB, Study No. 193, 2021. URL: https://ceri.ca/assets/files/Study_193_Full_Report.pdf

Sections of this study may be reproduced in magazines and newspapers with acknowledgment to the Canadian Energy Research Institute

January 2021 Printed in Canada

Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to all CERI staff involved in the production and editing of the material.

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE Founded in 1975, the Canadian Energy Research Institute (CERI) is an independent, registered charitable organization specializing in the analyses of economic and environmental issues in the energy production, transportation and consumption sectors. Our studies examine the most relevant energy issues affecting Canadians, painting a comprehensive picture of the impact policies and business decisions can have so that decision-makers in government, industry and other market segments can make sound decisions to help move Canada forward.

For more information about CERI, visit www.ceri.ca

CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: [email protected] Phone: 403-282-1231

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Table of Contents

List of Figures ...... vi

List of Tables ...... vii

Acronyms and Abbreviations ...... viii

Executive Summary ...... xi

: Objectives and Scope ...... 13

: Oil Sands Business Environment ...... 14

2.1 Background ...... 14 2.2 Market Access ...... 18 2.3 Regulatory Environment ...... 21 2.4 Climate Change and Greenhouse Gas Emissions Management ...... 22 Alberta Technology Innovation and Emissions Reduction Regulation (Government of Alberta 2019b) ...... 22 Federal Clean Fuel Standard (ECCC 2017b; 2017a) ...... 23 2.5 In Situ Bitumen Supply Cost...... 24 : In Situ Technologies and Processes ...... 27

3.1 Overview ...... 27 3.2 Emerging Technologies for Steam Generation ...... 28 Drum Boilers ...... 28 Dual Loop Steam Generation ...... 30 Direct Contact Steam Generation ...... 30 Flash Boilers ...... 31 Plasma Fired Steam Generator (PFSG) ...... 32 Boiler Blowdown Reduction Technology (BBRT) ...... 33 Partial and Full Cogeneration through Heat Recovery Steam Generation ...... 34 Cogeneration through Fuel Cells ...... 35 3.3 Solvent and Solvent-Assisted Extraction Processes ...... 38 Steam-Solvent Co-injection Processes ...... 38 Expanding Solvent SAGD (ES-SAGD) / Solvent-Assisted SAGD (SA-SAGD)...... 38 Solvent-Aided Process (SAP) ...... 39 Pure Solvent Injection Processes ...... 39

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Nsolv ...... 39 VAPEX ...... 39 Non-Condensable Gas Co-Injection Processes ...... 40 Steam and Gas Push (SAGP)...... 40 Modified SAGP (eMSAGP) ...... 40 3.4 Other Extraction Technologies and Processes ...... 41 Electromagnetic (EM) Heating Processes ...... 41 Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) Process ...... 41 Radio Frequency (RF) XL Process ...... 41 Steam-Surfactant Processes ...... 41 Exothermic Chemical Treatment (ECT) ...... 42 NextStream Catalyst Additive ...... 42 3.5 Wells and Well Pads ...... 44 Lean Manufacturing to Lean Drilling...... 45 Modularization ...... 45 3.6 Water and Wastewater Treatment ...... 45 Oil and Water Separation ...... 47 De-oiling ...... 47 Wastewater Treatment...... 47 Warm Lime Softening (WLS) ...... 47 Adding Dissolved Mg in Warm Lime Softening ...... 48 Elimination of Warm Lime Softening ...... 48 Evaporation ...... 49 Zero Liquid Discharge (ZLD) ...... 49 Electrocoagulation (EC) ...... 50 High Temperature Reverse Osmosis (HTRO) ...... 50 3.7 Machine Learning and Artificial Intelligence ...... 52 Veerum ...... 52 Ambyint ...... 53 Tachyus ...... 53 General Electric (GE) ...... 53 Guild One ...... 53 Real-time steam allocation workflow using ML for digital heavy oil reservoirs ...... 53

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SAS Analytics ...... 54 OPLII ...... 54 Fotech ...... 54 Vista Projects ...... 55 Applications for AI in Reservoir Engineering ...... 55 : Supply Costs and GHG Intensities ...... 57

: Uncertainties and Limitations ...... 64

Uncertainties ...... 64 Limitations ...... 64 Bibliography ...... 66

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List of Figures

Figure ES.1: Summary of Selected Technologies/Processes on Supply Cost & GHG Intensity ..... xii Figure 2.1: Crude Oil Prices (US$/bbl)…………………………………..………………………………………………….16 Figure 2.2: Total Operating Costs for In situ and Mining Projects (2019 C$/bbl)……………………….17

Figure 2.3: Emission Intensities by Project (kgCO2/bbl bitumen*)…………………………………………….18 Figure 2.4: Canadian Crude Exports to the US………….....…………………………………………………………..20 Figure 2.5: Canadian Crude Exports by US PADD Region (2019)……………………………………………….20 Figure 2.6: Pipeline Throughput and Crude Available for Export………………………………………………21

Figure 3.1: Simplified Drum Boiler Technology Flow Diagram ...... 29 Figure 3.2: Dual-Loop Technology Flow Diagram ...... 30 Figure 3.3: Direct Contact Steam Generator ...... 31 Figure 3.4: Flash Boiler Technology Flow Diagram ...... 32 Figure 3.5: Plasma Fired Steam Generation Technology Flow Diagram ...... 33 Figure 3.6: SAGD Central Processing Facility Incorporating Cogeneration ...... 34 Figure 3.7: MCFC Integration With an In Situ Oil Sands Facility ...... 35 Figure 4.1: Summary of Selected Technologies/Processes on Supply Cost & GHG Intensity ...... 63

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List of Tables

Table 2.1: Average Baseline Carbon Intensity Values for Liquid Fossil Fuels ...... 24 Table 2.2: In Situ (SAGD) Plant Design Assumptions ...... 26 Table 3.1: Summary of Steam Generation Technologies ...... 36 Table 3.2: Summary of Solvent, Solvent-Assisted, and Other Extraction Technologies ...... 43 Table 3.3: Summary of Well and Well Pads Technologies ...... 45 Table 3.4: Summary of Water and Wastewater Technologies ...... 51 Table 3.5: Summary of Digital and AI Technologies ...... 55 Table 4.1: Summary of Technology/Process on Supply Cost & GHG Intensity (Ranked by Supply Cost) ...... 59 Table 4.2: Summary of Technology/Process on Supply Cost & GHG Intensity (Ranked by GHG Intensity) ...... 61

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Acronyms and Abbreviations

AEO Annual Energy Outlook AER Alberta Energy Regulator AESO Alberta Electric System Operator AI Artificial Intelligence BBRT Boiler Blowdown Reduction Technology BPD Barrels Per Day CAPEX Capital Expenditures CCIR Carbon Competitiveness Incentive Regulation CEAA Canadian Environmental Assessment Agency CERI Canadian Energy Research Institute CFS Clean Fuel Standard

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent (including all greenhouse gases) CPF Central Processing Facility DCSG Direct Contact Steam Generation DO De-oiling EC Electrocoagulation ECCC Environment and Climate Change Canada EIA Environmental Impact Assessment (Canada) EM Electromagnetic eMSAGP Enhanced Modified SAGP ESEIEH Enhanced Solvent Extraction Incorporating Electromagnetic Heating ES-SAGD Expanding Solvent SAGD FWKO Free Water Knockout GE General Electric GHG Greenhouse Gas HTRO High Temperature Reverse Osmosis IEA International Energy Agency IGF Induced Gas Flotation

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IIoT Industrial Internet of Things IX Ion Exchange kt Kilotonnes m3 Cubic meters ML Machine Learning MM Million MMBPD Million Barrel Per Day Mt Million tonnes NCG Non-Condensable Gas NEB National Energy Board NRCan Natural Resources Canada OTSG Once Through Steam Generator ORF Oil Removal Filters OPEX Operating Expenditures PADD Petroleum Administration for Defense District PAW Process Affected Water PFSG Plasma Fired Steam Generation RF Radio Frequency RO Reverse Osmosis SaaS Software-As-A-Service SAC/WAC Strong Acid Cation/Weak Acid Cation SAGD Steam Assisted Gravity Drainage SA-SAGD Solvent-Assisted Steam Assisted Gravity Drainage SAGP Steam and Gas Push SAP Solvent-Aided Process SCO Synthetic Crude Oil SOR Steam To Oil Ratio ST Skim Tank TDS Total Dissolved Solids TIER Technology Innovation and Emissions Reduction Regulation TOC Total Organic Carbon

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TORR™ Total Oil Remediation and Recovery System TRL Technology Readiness Level US United States US EIA US Energy Information Administration USGC US Gulf Coast VAPEX Vapour Extraction WCS Western Canadian Select WTI West Texas Intermediate ZLD Zero Liquid Discharge

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Executive Summary

This study is an update to CERI Study 164 (CERI 2017), Economic Potentials and Efficiencies of Oil Sands Operations: Processes and Technologies (March 2017), focusing on in situ bitumen production processes and technologies that are in the early demonstration stage through to recent commercialization. Since Study 164 was issued, processes and technologies have been demonstrated that reduce costs through (i) lowering steam generation costs and (ii) use of solvents and diluents in place of steam or in combination with steam. These developments span the in situ process life cycle from surface facilities, well and well pads, through to water and water treatment.

Note that to determine supply costs and when discussing market conditions, this study directly updates CERI Study 183 (CERI 2019), Canadian Oil Sands Supply Costs and Development Projects (2019-2039), issued in July 2019, which the reader is encouraged to refer directly to for a more fulsome discussion of the economics and market conditions related to oil sands.

Several of the leading drivers behind the development and adoption of newer in situ processes and technologies are lower netbacks for bitumen combined with higher supply cost relative to conventional crude oils. Another key driver is the current regulatory environment, and public opinion focused on greenhouse gas emissions reductions.

The technologies under consideration in this report are, for the most part, improvements and optimizations of existing technologies and processes, leading to incremental changes over stepchange improvements.

A subset of newer technologies and processes lower the supply cost below the Base Design’s C$41/bbl and GHG emissions intensity below 61 kg CO2e/bbl (Figure ES.1). The largest reductions are associated with either improved steam generation or solvent and solvent-assisted technologies.

While many of the newer technologies increase supply costs due to higher capital costs or, in the case of solvent and solvent-assisted process, the cost of lost solvents, overall supply costs could be reduced by C$5 – C$7/bbl with a potential to achieve a total reduction of C$10 – C$11/bbl if solid oxide fuel cells and eMSAGP prove viable.

Depending upon configurations, overall GHG intensity could be reduced by 15 – 20 kg CO2e/bbl with the potential to achieve a total reduction of 42 – 47 kg CO2e/bbl if solid oxide fuel cells and some solvent technologies prove viable.

Some technologies and processes offer a partial upgrading effect resulting in product quality improvements. Therefore, field supply costs are also compared on a diluted bitumen (dilbit) basis to quantify this impact. If diluent requirement is reduced by around 50%, reduction in dilbit supply cost relative to the base design is observed to be up to C$4/bbl.

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Figure ES.1: Summary of Selected Technologies/Processes on Supply Cost & GHG Intensity

Base Design GHG Intensity

Base Design Supply Cost

Source: CERI

Note: The number preceding each technology/process is for plotting proposes only

This report also presents detailed breakdowns of CAPEX and OPEX contributions to estimated supply costs for each technology, in addition to the total capital and operating costs of potential project investments.

However, it must be noted that bitumen reservoirs’ characteristics vary significantly across Alberta and within any specific reservoir. This is very relevant because the applicability and performance of any in situ extraction process depend on the specific reservoir's characteristics. Additionally, any water and wastewater treatment technologies' applicability and performance are impacted by water’s quality and solid materials within the reservoir.

Except for Machine Learning and Artificial Intelligence, the specific technologies described are not as yet considered by CERI to be commercially proven.

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: Objectives and Scope

The objective of this study is to identify new and emerging process and technology options:

• For deployment in Alberta’s steam assisted gravity drainage (SAGD) in situ bitumen production sector within the next five to seven years; and • To assess their potential to reduce supply costs and greenhouse gas emissions.

Cyclic Steam Stimulation (CSS) is another common in situ process, similar to SAGD. However, most in situ recoverable bitumen deposits in Alberta are more suitable for SAGD than CSS. Therefore, SAGD is used as the reference process in this report. This study concentrates on processes and technologies for:

• Emerging Technologies for Steam Generation • Solvent and Solvent-Assisted Extraction Processes • Other Extraction Technologies and Processes • Wells and Well Pads • Water and Wastewater Treatment • Machine Learning and Artificial Intelligence

This study is an update to CERI Study 164 (CERI 2017), Economic Potentials and Efficiencies of Oil Sands Operations: Processes and Technologies (March 2019), focusing on in situ bitumen production processes and technologies. The technologies being examined could be commercially proven and deployed within five to seven years, i.e., nominally by 2025 – 2027.

The results of CERI’s thirteenth annual study of Canada’s oil and gas supply costs and market dynamics are summarized in this paper for context. For more details, the reader is encouraged to refer to CERI Study 183 (CERI 2019), Canadian Oil Sands Supply Costs and Development Projects (2019-2039), from July 2019.

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: Oil Sands Business Environment

• Challenges to oil sands production exist on many fronts, including market access and volatility of the oil sands price differential. • Oil sands production is affected by the regulatory environment that is currently focused heavily on reducing Greenhouse Gas (GHG) emissions. Existing regulations at the Federal and Provincial level include Alberta Technology Innovation and Emissions Reduction Regulation, the Alberta Oil Sands Emissions Act and the Clean Fuel Standard. • COVID-19 pandemic had a significant adverse impact on the oil sands sector. It is unclear how long the pandemic will last and what the overall impact will be on the

2.1 Background The health emergency caused by the COVID-19 pandemic is having a severe adverse impact on the global economy. This period is being equated to the state of the economy witnessed during the 1930s Great Depression (IEA 2020). At the time of writing, it was still unclear how long the current health crisis will continue and how deeply it will impact economic growth, employment, trade, social behaviour, and capital investment.

Even before the pandemic, the decline in global oil prices, surging crude inventories and geopolitics have impacted the crude oil industry and slowed the pace of upstream investment worldwide – including oil sands development in Canada. The global market remains volatile, as witnessed by temporary negative oil prices in April 2020. There are early signs of improvement, but the recovery ahead is a long road filled with uncertainty. Indeed, prices have recovered from the negative territory.

However, Canada’s oil sands are still suffering from low capital investment, with many companies slashing their 2020 investment levels, ultimately impacting new drilling, jobs in the sector, production growth, and overall economic benefits to the rest of the economy (Province 2020). While some early shut-in production is coming back, it is still uncertain how much and how quickly it will come online. Canada is still among the top five global crude oil producers, and synthetic crude oil (SCO) and bitumen production is still expected to take the lion’s share of total Canadian crude oil production. However, many factors need to align, one of which is the need for expansion in existing export oil pipeline capacity, in addition to higher oil prices. As Canadian crude oil continues to be a sought-after barrel, especially in US Midwest and the Gulf refineries, the leverage of these resources for economic benefits to the nation will depend on connecting this growing supply with downstream demand.

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Figure 2.1: Crude Oil Prices (US$/bbl)

$120.00 $115.00 $110.00 $105.00 $100.00 $95.00 $90.00 $85.00 $80.00 $75.00 $70.00 $65.00 $60.00 $55.00 US$/bbl 1 2 $50.00 $45.00 4 $40.00 $35.00 $30.00 $25.00 3 $20.00 $15.00 $10.00 $5.00 $-

WCS-WTI Differential (US$/bbl) WCS Price ($US/bbl) WTI Price ($US/bbl) Brent Price (US$/bbl)

Source: Baytex Energy, US EIA. Figure by CERI.

Notes: (1) Marks historical period of light-heavy (WTI-WCS) differential of US$15/bbl after the 2014 price drop due to a global oversupply environment, with increasing production coming from the US. As a reaction to falling crude prices, OPEC and other global producers decided to reduce production and exports to correct falling prices; (2) The regional lack of export pipeline capacity led to widening differential and more crude by rail, costing producers higher transportation fees to ship oil; (3) Differential reached record high levels due to ongoing lack of export pipeline capacity; the Government of Alberta implemented a provincial production curtailment program; (4) the ongoing pandemic had an adverse impact on global oil demand, causing the oil prices to plummet. Since May, some demand was brought online and reversed oil prices' downward direction.

For oil sands opponents, sustained decline in investment provides a point of view that the industry is too costly to compete. What this view ignores, however, is continuing capital and operating cost reductions captured by project operators through project efficiency initiatives such as debottlenecking and efforts at reducing costs through technological improvements and other operational measures. The total operating costs have decreased year-on-year for most existing projects, in situ and integrated and stand-alone mining. Historical total operating costs for selected projects are shown in Figure 2.2. The sampled operating costs for in situ producers, mostly SAGD facility operators, shown in the top part of Figure 2.2, for integrated and stand-alone mining producers – sampled operating costs are shown in the bottom part of Figure 2.2. The selected in situ projects, for which operating costs are presented, represent 53% of all in situ or 25% of total bitumen production. The selected mining projects represent 81% of all mining or 41% of total bitumen production. From 2014, when oil prices crashed, to 2018, total operating costs for both oil sands mining and in situ producers fell on average by 40%, and in some cases, operators slashed costs in half. SAGD

January 2021 16 Canadian Energy Research Institute producers achieved a 48% cost reduction between 2014 and 2018 and a year-on-year reduction of 7% in 2018 compared to 2017. Integrated and stand-alone mining projects’ operating costs, on average, declined by 32% in 2018 versus 2014. However, the 2019 costs, for the most part, remained flat or slightly increased compared to 2018 costs in real 2019 dollars. Figure 2.2: Total Operating Costs for In situ and Mining Projects (2019 C$/bbl)

$30.00

$25.00

$20.00

$15.00

$10.00 CAD2019$/bbl

$5.00

$- 2014 2015 2016 2017 2018 2019

Christina Lake Cenovus Energy Firebag and MacKay River Suncor Energy Foster Creek Cenovus Energy Jackfish Devon Canada Peace River Cadotte Creek CNRL Great Divide Connacher Oil and Gas Christina Lake Regional MEG Energy

$60.00

$50.00

$40.00

$30.00

$20.00 CAD2019$/bbl $10.00

$- 2014 2015 2016 2017 2018 2019

AOSP Muskeg River CNRL Horizon CNRL Kearl Lake Imperial Oil Limited Suncor Base Mine Suncor Energy Inc. Syncrude North and Aurora North Mines

Source: CanOils, CERI Growth in commercial oil sands production has also caused absolute GHG emissions related to oil sands development to increase but at a declining rate per barrel. Figure 2.3 illustrates the historic emission intensities for selected projects from 2009 to 2017 (the most recent public data available). It is observed that between 2009 and 2016, average emission intensity levels of onstream projects have decreased by 11, 15 and 10% for SAGD, mining and upgrading, respectively. Year-on-year changes do not indicate a significant reduction; SAGD projects, on average, decreased their emission intensity by 1% in 2017 compared to 2016, with some individual projects showing a decrease of 18% and some an increase of as much as 15%.

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Figure 2.3: Emission Intensities by Project (kgCO2/bbl bitumen*)

A. SAGD Projects 180

160

140

120

100

80 kgCO2eq./bbl 60

20 2009 2010 2011 2012 2013 2014 2015 2016 2017

Christina Lake Firebag Foster Creek Jackfish Surmont (ConocoPhillips) Orion Christina Lake Regional

B. Mining Projects 90

kgCO2eq./bbl 30

- 2009 2010 2011 2012 2013 2014 2015 2016 2017

AOSP Jackpine AOSP Muskeg River Kearl Lake

C. Upgraders 150

130

110

kgCO2eq./bbl 70

30 2009 2010 2011 2012 2013 2014 2015 2016 2017

AOSP Scotford Upgrader Horizon Upgrader Lloydminster Upgrader Suncor UpgraderU1 & U2 Syncrude Upgrading

Source: Canoils, CERI. Note: (*) Emissions intensities for Suncor and Syncrude Upgrading are not broken down by mining and upgrading. Hence it’s presented on the kgCO2eq/bbl of SCO basis.

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Emission intensities for integrated mining and upgrading projects on average increased by 1% in 2017; emission intensity just for upgrading projects decreased 5% year over year. Numerous policies and regulations have been adopted in recent years to limit and reverse oil sands emission growth while sustaining production levels and minimizing economy-wide impacts. Some of the mechanisms include intensity-based carbon pricing to protect trade- exposed sectors, limit carbon leakage, an absolute emissions cap on oil sands, and a federally mandated carbon tax.

2.2 Market Access

As a consequence of the rapid growth in American oil production, inland refining markets in the US Midwest (current recipients of most of the Canadian heavy imports) have been experiencing a surplus of cheap light tight oil, which leaves Canadian heavier sour crude oil subject to price markdowns due to quality and bottlenecks in their delivery infrastructure. This situation provides Canadian producers with a financial incentive to expand market access in the United States, Canada, and beyond. It also highlights the risk of over-reliance on limited markets and the need for options.

Expansion of pipeline infrastructure and shipping routes to international markets and the US would create opportunities for Canadian oil producers and benefit the Canadian economy. Through increasing market access for products, Canada will compete in global markets:

• capture additional tax revenues from producers; • increase employment in energy and non-energy sectors; • be able to continue to fund the critical social structure of this country, not to mention have a potential to invest in further research and development and innovation in Canadian energy systems. Allocating exports to other markets such as Asia and Europe would also reduce dependence on the US markets. Total Canadian crude exports to the US increased 2.4% in 2019, reaching 3.8 million barrels per day (MMBPD) compared to 2018 levels, with the largest share of total exports coming from heavy sour crudes; in 2019, its share decreased to 65% (Figure 2.4).

The US Gulf Coast (USGC) or PADD 3 is one of the world’s largest refining centres. Its considerable heavy oil processing capacity presents the largest opportunity for Western Canadian heavy crude oil supply, making it Canadian heavy producers’ first target for market access. Canadian heavy crude oil competes for market share in the US Gulf Coast with heavy crude oil from Latin American producers, mainly Mexico, Venezuela, Brazil and Ecuador. Mexico and Venezuela are the main heavy crude oil exporters to the US Gulf Coast, accounting for over 45% of total crude oil imports to the US Gulf Coast. More recently, crude exports from Mexico and Venezuela have

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been declining due to domestic social and economic reasons, providing a further opportunity for Canadian heavy crude to replace some of the lost volumes and expand their market share in the US Gulf.

Figure 2.4: Canadian Crude Exports to the US

4,000

3,500

3,000

65% 2,500 68% 66% 62% 61% 2,000 60% KBPD 59% 59% 1,500 59% 55% 57%

1,000

500

- 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Light Sweet Light Sour Medium Heavy Sweet Heavy Sour

Source: EIA, CERI The US Midwest region or PADD 2 is still the dominant market for Canadian crude, capturing almost 70% of all Canadian imports. However, PADD 3 or the US Gulf Coast is a growing market, evidenced by the growing Canadian crude imports into that region. Over the last ten years, the volumes have increased three-fold, amounting to 500 thousand barrels per day (KBPD) in 2019, most of which is heavy crude supply (Figure 2.5).

Figure 2.5: Canadian Crude Exports by US PADD Region (2019)

3,000.0

2,500.0

2,000.0

1,500.0 KBPD

1,000.0

500.0

- PADD1 (East Coast) PADD2 (Midwest) PADD3 (Gulf Coast) PADD4 (Rocky PADD5 (West Coast) Mountain)

Light Sweet Light Sour Medium Heavy Sweet Heavy Sour

Source: EIA, CERI

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Figure 2.6 illustrates the crude and liquids pipeline throughput against total available crude supply for export out of Western Canada from 2007 to present. Since the price crash of 2014, there has been a disconnect between available pipeline capacity versus how much crude is available for export.

As pipelines became full, the differential between Canadian WCS and US WTI started to widen, which prompted domestic producers to move crude by rail, reaching all-time new records. However, that did not alleviate the challenge completely, as the supply continued to build, filling up the domestic storage to the brim. The provincial government responded with a province-wide production curtailment at the end of 2018, carried through in 2019 and 2020, with a recent partial lift on the production limits.

Figure 2.6: Pipeline Throughput and Crude Available for Export

Source: CER, CERI Note: The volume of oil available for export was calculated by subtracting domestic refining capacity from total supply volumes. The throughput volumes for all major pipelines were sourced at their respective international terminals and summed up to obtain the total throughput volume. With the ongoing opposition to the federally-approved and owned Trans Mountain pipeline expansion and Enbridge’s Line 3, doubts are mounting on whether export pipeline capacity will increase by the approximately 1 MMBPD needed to alleviate some existing constraints in the mid to long-term.

More recently, pipeline companies have made several announcements on their plans to add additional pipeline capacity to alleviate some egress issues. Enbridge announced how it proposes to add 450,000 barrels per day (BPD) to its existing pipeline system without building new pipelines (Oilsands Magazine, n.d.). This is expected to be phased in over the next two years, with another 100,000 BPD of system upgrades expected to be completed by 2022.

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Enbridge’s plan involves a major change to their Southern Lights pipeline. Currently, it delivers condensate, used as diluent for heavy oil transport, from the US Midwest region into the Edmonton area. The plan is to reverse the line, subject to regulatory approval but could be completed by 2023. If approved, another 150,000 BPD of light oil export capacity out of Western Canada.

Enbridge has also stated it can boost capacity on its Express Line into the Rocky Mountains region by up to 60,000 BPD through the addition of chemicals and upgrades to pump stations. Those could potentially be completed by the end of 2020.

Another Canadian company, Plains Midstream Canada, announced an expansion on its Rangeland pipeline for additional delivery capacity both north to Edmonton, Alberta and south to the border at Carway, Alberta. This expansion is subject to receiving sufficient commitments from shippers and the receipt of necessary permits and regulatory approvals. It will provide incremental takeaway capacity for the East Duvernay and other Rangeland-area production and south egress access out of the Edmonton market hub. Combined, the expansion will increase Rangeland's current light crude oil capacity to approximately 200,000 BPD. Service between Edmonton and Sundre will be expanded from 50,000 to approximately 100,000 BPD and, additionally, will be capable of bi-directional service. The pipeline from Sundre south to the border will be expanded from 20,000 to 100,000 BPD. The expansions will be staged into service during the last half of 2019, with full capacity realized in 2021 (Plains Midstream Canada 2019).

Although the need to expand and reach new markets for oil sands is pressing, production and pipeline projects associated with oil sands have increased scrutiny, contributing to delays and uncertainty. Although not every factor will influence future markets for oil sands, some of the most prominent ones include regulatory processes, local concerns, greenhouse gas emissions and climate change policies, and Indigenous People’s rights in Canada.

Also, the ongoing COVID-19 pandemic has a significant impact on trade, including commodities such as crude oil. It is still unclear how long this pandemic might last and how extensive the impact could be. 2.3 Regulatory Environment

Describing regulations governing the oil and gas sector within Canada, including pipelines, can be challenging due to overlapping federal and provincial jurisdiction, settled, challenged and unsettled lands and rights claims with Canada’s First Nations (Indigenous peoples), and numerous court challenges on the rigour and sufficiency of environmental assessments.

Of notable concern within the oil and gas sector and the Alberta and Saskatchewan governments is newly proclaimed federal legislation, commonly referred to as Bill C-69, that lead to the enactment of the Impact Assessment Act, the Canadian Energy Regulator Act (replacing the National Energy Board), amendments to the Navigation Protection Act, as well as consequential amendments to other Acts. In summary:

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• The Canadian Environmental Assessment Act (2012) was repealed, and in its place, the Impact Assessment Act came into force, and in doing so creates the Impact Assessment Agency of Canada as the authority responsible for impact assessments; • The National Energy Board Act was repealed, and in its place, the Canadian Energy Regulator Act came into force, which establishes the Canadian Energy Regulator whose role is to regulate the exploitation, development and transportation of energy within Parliament’s jurisdiction. • Amends the Navigation Protection Act to, among other things, rename it the Canadian Navigable Waters Act with a comprehensive definition of navigable water and a requirement that the Minister must consider any adverse effects that the decision may have on the rights of the Indigenous peoples of Canada.

Notable for the in situ sector is that it is currently proposed under regulations (Government of Canada 2019) being drafted under the Act that in situ oil sands projects with production over 2,000 m3 per day, and expansions of in situ facilities resulting in an increased production capacity of 50% or more, would be regulated under this Act unless the Alberta government maintains a legislated, hard cap on greenhouse gas emissions described in the next Section 2.4. 2.4 Climate Change and Greenhouse Gas Emissions Management

Canada's federal government has implemented and is developing additional legislation and regulations to address climate change through, among other measures, regulating emissions from the oil and gas sector and reducing the carbon intensity of energy in Canada, including fossil fuels. In addition to federal activities, provincial governments have also implemented legislation and regulations independently. Depending upon the specific provincial government, the federal and provincial approaches can be aligned with or in conflict with the federal legislation. Further, several provinces are challenging federal constitutional authority to impose certain regulations.

Given this dynamic situation, the following sections are only intended to provide the reader with an overview of current federal and Alberta approaches to regulating GHG emissions within the bitumen in situ sector, which is in itself limited to Alberta. For this study's purposes, given the scope of this work and uncertainty around federal and provincial regulations, modelling and economic analysis are based on a C$30/tonne CO2e tax applied to all fuel, assumed to be natural gas, combusted within a SAGD facility. The C$30/tonne CO2e price equals the price in the Alberta regulations for industry and the federal carbon tax program. This equates to a cost of C$1.90/bbl of supplied bitumen.

Alberta Technology Innovation and Emissions Reduction Regulation (Government of Alberta 2019b) The Technology Innovation and Emissions Reduction (TIER) Regulation came into force on January 1, 2020, replacing the Carbon Competitiveness Incentive Regulation (CCIR). The TIER regulation applies to facilities that emitted 100 kt GHG or more per year of GHGs in 2016 or a subsequent year.

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The core attributes of the TIER are:

• Facility specific GHG intensity benchmark determined by the facility’s past performance, with alternatives available for in situ bitumen production based on overall industry best performance; • New facilities being given time to come online and establish normal operations, with an initial 95% target; • Target in 2020 of 90% of that benchmark, with stringency increasing by 1% per year; o Exemption for emissions from electricity generation (with co-generation) and “industrial process” emissions, i.e., chemical reactions in the production process; • Compliance, subject to specific limitations, can be achieved through: o On-site emission reductions, o Use of emissions performance credits (traded between facilities), o Use of Alberta-based emissions offsets, and • Payment into a TIER compliance fund at $30/tonne of CO2e for 2020 and increasing by $10/tonne annually up to 2030.

Alberta Oil Sands Emissions Limit Act (Government of Alberta 2012; 2019a)

Oil sands operations currently emit approximately 81 MT per year of GHGs (ECCC 2017). These facilities are currently obliged to reduce emissions or pay into the provincial levy through TIER. Under the Alberta Oil Sands Emissions Limit Act, GHG emissions from the oil sands sector are limited to a maximum of 100 MT/a, with provisions for cogeneration and new upgrading capacity. This limit provides room for growth, improving performance incentivized by the TIER policy. The current projection is that the limit would be reached by 2030.

Federal Clean Fuel Standard (ECCC 2017b; 2017a) Fuels The proposed Clean Fuel Standard (CFS) will require fossil fuel suppliers to reduce the lifecycle carbon intensity of fuels (i.e., extraction, production, distribution, and use of) so that by 2030, the carbon intensity of liquid fuels will be 10 – 12% lower than they were in the 2016 base year. The regulation will also apply to gaseous and solid fuels, such as natural gas and petroleum coke. Environment and Climate Change Canada (ECCC) has estimated that this will reduce Canada’s annual greenhouse gas emissions by 30 MT per year by 2030. The CFS is intended to incent the innovation and adoption of clean technologies in the oil and gas sector and lead to the development and use of low-carbon fuels throughout the economy.

The CFS will not differentiate among crude types with average lifecycle carbon intensities for refined petroleum products (Table 2.1) accounted for the average crude types used in Canada.

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Table 2.1: Average Baseline Carbon Intensity Values for Liquid Fossil Fuels

Fuel Carbon Intensity (g CO2e/MJ) Gasoline 92 Diesel 100 Kerosene 88 Light Fuel Oil 84 Heavy Fuel Oil 99 Jet Fuel 86

Oil and Gas Facilities Under the proposed CFS, existing oil and gas facilities will be provided with an incentive to reduce the carbon intensity of the fuels they produce. In contrast, new oil and gas facilities will be incented to use the most efficient technologies and processes.

The CFS recognizes that a benchmark may not be possible for some facilities, including in situ oil sands facilities. Project-specific benchmarks that go beyond other regulatory requirements, i.e., electrification, co-generation and methane reductions, could be considered.

There could be specific cases for all facility types where a typical new facility would not have implemented an innovative technology or practice but may be encouraged to do so due to credit creation opportunities under the CFS. In these cases, the quantification methodologies will provide the same credit creation opportunities to new facilities and existing facilities without using a benchmark. These cases would be for carbon capture and storage, enhanced oil recovery, low-carbon-intensity electricity integration and co-processing of biocrudes in refineries and upgraders. 2.5 In Situ Bitumen Supply Cost

Supply cost is the constant dollar price needed to recover all capital expenditures, operating costs, royalties and taxes and earn a specified return on investment. This study's supply costs are calculated using an annual discount rate of 10.0% (real), which is equivalent to an annual return on investment of 12.0% (nominal) based on the assumed annual inflation rate of 2.0%.

The plant gate supply costs, which excludes transportation and blending costs, were determined to be C$40.61/bbl for a SAGD project (Figure 2.7). After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing are US$52.84/bbl.

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Figure 2.7: Total Plant Gate in Situ (SAGD) Bitumen Supply Costs

aReturn on capital included. Source: CERI

This is based on the plant design assumptions summarized in Table 2.2, which are fully described in the CERI study, Canadian Oil Sands Supply Cost And Development Projects (July 2019).

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Table 2.2: In Situ (SAGD) Plant Design Assumptions

SAGD Base Design Project Design Parameters Stream day capacity 30,000 BPD Production Life 30 Years Capacity Factor (Annual Average) 90% Steam to Oil Ratio 3 Capital Expenditures (2018 C$) Initial C$1,140 MM (@ C$38,000/bbl) Sustaining Capital C$43.8 MM/yr Operating Working Capital 45 Days Operating Costs (2018 C$) Total Operating Costs C$92.0 MM/yr Non-Energy Operating Costs C$64.4 MM/yr Energy Requirements Natural Gas 35,910 GJ/d Electricity Purchased 300 MWh/d Other Project Assumptions Abandonment and Reclamation 2% of Total Capital Source: CanOils, CERI

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: In Situ Technologies and Processes

• There are technology options for improving operating costs and reducing energy use and GHGs in multiple areas, including steam generation, adoption of solvent and solvent-assisted extraction, and water and wastewater treatment. • Based on available information, many technologies listed below are in the Technology Readiness Level (TRL) stage 6 and 7, making them ready for commercialization within five years. • For the most part, the technologies are improvements and optimizations of existing technologies and processes, leading to incremental changes over step-change improvements. • Machine Learning and Artificial Intelligence technologies that provide economic and GHG benefits are currently available for use with in situ facilities.

3.1 Overview

Alberta’s bitumen can be open-pit mined or extracted in situ (in place). Approximately 80% of the bitumen reserves are too deep to be economically mined and given the tar-like properties of bitumen, too dense to be produced through conventional drilling. In situ extraction, commercialized in the 1980’s, is economically viable when steam is injected into the well (Oil Sands Magazine 2020).

The two common in situ processes are Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). 1The selection of SAGD versus CSS is a function of the reservoir's geology. With SAGD dominating the Athabasca deposit’s plant design, which comprises ~85% of Alberta’s in situ recoverable bitumen. CSS is common within the Cold Lake deposit. For this reason, the focus of this study has been on SAGD, although many of the surface processes are common to both SAGD and CSS facilities.

In a SAGD facility:

• Two horizontal wells are drilled, which are approximately 5 meters apart. • High-pressure steam is injected through one of the wells, which has been drilled above the lower production well. • The steam heats the surrounding bitumen, reducing its viscosity, and it then flows under gravity to the lower production well.

1 Note that in addition to SAGD and CSS, which commonly utilize steam to heat the bitumen and thereby reduce its viscosity, some deposits contain bitumen that has a low enough viscosity to be pumped to the surface, along with sand contained in the reservoir, using submersible pumps. This technology is known as Cold Heavy Oil Produced with Sand (CHOPS).

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• The resulting bitumen/water emulsion is pumped to the surface and is sent to the processing plant. • The recovered water is treated and recycled back into the process.

In a CSS facility:

• A single well is drilled. • High-pressure steam is injected for several weeks into the reservoir to heat the bitumen and reduce its viscosity. • The bitumen is then allowed to soak for several days or weeks, then the flow is reversed, bringing the bitumen/water emulsion to the surface.

Steam generation is a critical part of the SAGD bitumen production process. Steam is generated at a Central Processing Facility (CPF) and transported to well pads, and injected into the reservoir, heating the in situ bitumen for extraction.

Oil sands in situ recovery operations traditionally use Once Through Steam Generators (OTSGs) to vaporize treated water. OTSGs can face various operational challenges and often require downstream vapour-liquid separators to increase the steam quality (reduce wetness) prior to injection into a SAGD well. The OTSGs are typically designed for 80% steam quality, but many run between 70 – 80% steam quality, and 78% is considered the industry standard (IST 2016).

Operators require emerging steam boiler technology to produce high-quality steam, with little blowdown and high boiler efficiency using poor quality feed water. A major economic driver for the SAGD process is reducing costs associated with water treatment, while a major GHG emissions driver is the reduction in fuel consumption from steam generation. Both these drivers can be addressed with emerging steam generation technologies.

With respect to the collective importance of improving oil sands facilities' environmental performance, Alberta’s oil sands sector created Canada’s Oil Sands Innovation Alliance (COSIA). COSIA is an innovative model designed to address the key technology issues in oil sands development. It is an alliance of oil sands producers focused on four Environmental Priority Areas (Water, Greenhouse Gases, Land and Tailings) with a mission to work collaboratively to accelerate the pace of environmental performance improvement. COSIA members account for over 90% of oil sands production, and all have formally signed on to the COSIA model of innovation and technology sharing. 3.2 Emerging Technologies for Steam Generation Drum Boilers

Drum boilers, also called water tube boilers, consist of two drums - a mud drum and a steam drum - connected by a series of pipes (Figure 3.1). Feedwater enters the lower mud drum, comes into contact with a heating element and evaporates as it is circulated through pipes from the

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mud drum to the steam drum. Natural circulation in drum boilers allows for hot water to rise and colder water to fall. Superheated steam is then taken off the top of the steam drum.

Drum boilers have some advantages over traditional OTSGs. Drum boilers can provide high steam quality, up to 100%, eliminating the need for downstream steam separators. Drum boilers also can effectively separate solids leading to reduced wastewater blowdown. However, they have much higher heat flux than traditional OTSGs, which increases fouling and scale deposition on the heating tubes. As a result, high-quality feed water is required with water treatment, often including evaporators. When they are combined with an evaporator, feed water is of higher quality, reducing scaling compared to OTSGs.

Drum boilers have a higher turndown capacity (a measure of the operating flexibility) than OTSG and have a smaller physical footprint than OTSG due to multiple circuits of small-bore piping.

Figure 3.1: Simplified Drum Boiler Technology Flow Diagram

Source: GTI, 2017. There are advantages and disadvantages to both technologies. The best system depends on the production site layout and size, reservoir characteristics, wastewater disposal capacity, fresh make-up water economics, and company experience (GTI, 2017).

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Dual Loop Steam Generation

The Dual Loop steam generation process involves heating feed water in a boiler indirectly through a closed-loop system using a thermal fluid (Figure 3.2). The thermal fluid is heated to high temperatures through fuel combustion, and then steam is then generated from feed water through heat exchange with the thermal fluid. The feed water is never in contact with a direct- fired heat transfer surface like traditional OTSG or Drum boiler technology. Some of these technologies are currently being piloted by major SAGD oil producers (Hipvap 2017).

Figure 3.2: Dual-Loop Technology Flow Diagram

Source: (GTI 2017)

These indirect heating processes operate at moderate heat fluxes, which reduces fouling. This removes the need for extensive water treatment, reduced capital costs, and improved reliability (Hipvap 2020).

There are additional pumping and electrical demands associated with the Dual Loop systems that can increase GHG emissions. There are increased pumping requirements for low-quality steam generation, and some of these technologies yield steam quality as low as 20% prior to steam separation (GTI 2017). Also, the surface-based dual loop process requires twice the surface footprint of a traditional OTSG. However, Dual Loop boilers' economics are favourable due to reduced wastewater treatment system requirements.

Vendors of Dual Loop steam generation technology include Aalborg CSP, eSteam, and Hipvap. These technologies vary by type of thermal fluid and the process used. Aalborg CSP uses steam as a thermal fluid and surface heater and boiler process. Hipvap uses an unspecified thermal fluid with a surface steam generation process, and eSteam uses an unspecified thermal fluid with a down-hole steam generator.

Direct Contact Steam Generation

The Direct Contact Steam Generation (DCSG) process involves steam generation from the combustion of fuel gas with oxygen in direct contact with feed water in a high-pressure, high- temperature combustor (Figure 3.3). The flue gas stream contains both steam and non- condensable products of combustion, carbon dioxide, and waste solids. The flue gas and steam

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mixture goes through solids filtration and non-condensable gas (NCG) separation prior to steam injection.

Figure 3.3: Direct Contact Steam Generator

Source: (GTI 2017)

There are several advantages to DCSG. There is no surface fouling as there is no heat transfer through boiler walls. DCSGs can take low-quality feed water, eliminating the need for water treatment. There is also no liquid injection or blowdown. Steam generation efficiencies are over 10% higher than conventional OTSG. These efficiencies are offset by increased electrical requirements to increase air and fuel up to boiler pressure. The DCSG process is more compact than the traditional OTSG process and may lend itself to pad-level application.

DCSG requires oxygen separation and compression and downstream non-condensable gas separation. Despite this, capital associated with air separation and non-condensable gas separation is expected to be less than water treatment cost (GTI 2017).

A disadvantage of DCSG over OTSG is the production and separation of non-condensable gases. There is ongoing research and piloting associated with injecting non-condensable gases, including CO2. If CO2 injection is shown not to have adverse effects on the reservoir, there is an additional cost from installing NCG separation equipment. There is significant potential for GHG emissions reductions if flue gases can be injected into the reservoir. Suncor is currently co-injecting CO2 with steam through DCSG to study reservoir performance and sequestration potential (Cogion 2018).

Flash Boilers

Flash boilers generate steam without boiling, as shown in Figure 3.4. The technology involves heating produced feed water at sufficiently high pressure but below boiling point pressure so that it stays in a liquid phase. The liquid is then rapidly injected into a low-pressure drum to depressurize or flash the liquid to generate steam. Ninety percent of the feed water is converted to high-quality steam. Liquids and solids are then separated, with most impurities remaining in the water phase. The remaining water is recycled and mixed with incoming feedwater and returned to the boiler (COSIA 2017).

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Figure 3.4: Flash Boiler Technology Flow Diagram

Source: (FSG)

The technology has the potential to eliminate the need for water treatment. However, as of 2017, the technology had only been tested on produced water having <2ppm hydrocarbon, which is too high to eliminate current water treatment (GTI 2017).

A flash steam generation field pilot-detailed engineering study was initiated in 2017 among FSG Technologies, Cenovus, CNOOC and BP (COSIA 2017). No results have been made public yet.

Plasma Fired Steam Generator (PFSG)

Plasma Fired Steam Generation (PFSG) involves a combination of submerged plasma arcs and electrical resistive heating (Figure 3.5). The plasma arcs provide the heat required to produce steam between electrically conducting electrodes and the water’s electrical resistivity. The solids settle at the steam generator base and are removed through a blowdown stream (Pyrogenesis 2016). The efficiency of the PFSG is reported to be over 95% and requires only electricity to run (GTI 2017).

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Figure 3.5: Plasma Fired Steam Generation Technology Flow Diagram

Source: Pyrogenesis, 2016

Feedwater is directly supplied from the free water knockout without further water treatment and reducing capital costs. PFSG is highly tolerant of water quality variations, including conductivity, pH, temperature, and solid loading. Pyrogenesis reports a blowdown ratio of 10- 15% in early testing. PFSG technology is reported to have a lower capital cost. However, there are higher operating costs due to electricity demand.

One of the advantages of using plasma over gas or electric heat elements is the intense heat of the plasma keeps the electrode tips highly resistive to fouling because heat transfer does not occur through a heated surface.

Pyrogenesis is in TRL 6 with a prototype fully designed, built and operating as of 2017. Pyrogenesis states that PFSG technology is a modular, transportable solution for steam generation requiring only electricity and feed water directly from FWKO (GTI 2017). PFSG technology can be applied to modular development, where steam generation can occur in direct proximity to pad sites.

Boiler Blowdown Reduction Technology (BBRT)

In 2011, Cenovus commercialized a technology called Boiler Blowdown Reduction Technology (BBRT), where OTSGs with rifled tubes2 are placed in series. Currently, ~20% of boiler feed water

2 Rifled (also known as ribbed) tubes consist of internal ribs resembling the “rifling” within a cannon or rifle barrel. The internal rifling increases surface area but, more importantly, increases turbulence by inducting a centrifugal force in the fluid in the tube which increases the rate of heat transfer.

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is not converted to steam and is either treated for reuse or disposed of because of impurities. The secondary boiler in BBRT converts what would be wastewater into additional steam. Feeding blowdown water from a primary OTSG to a secondary OTSG without water treatment reduces wastewater. Removing the additional water treatment can also reduce oil sands water use intensity, physical footprint and greenhouse gas emissions.

Partial and Full Cogeneration through Heat Recovery Steam Generation

The cogeneration process involves the combustion of natural gas in a gas turbine that spins a generator to produce electricity. Flue gas from the combustion process is passed through a Heat Recovery Steam Generator (HRSG), where the waste heat is used to create steam (Figure 3.6). Cogeneration is well suited for application to SAGD operations because it can replace OTSGs and improve efficiency. Cogeneration is a mature, proven commercial technology in SAGD operations. Cogeneration can increase the overall central processing plant efficiency, use less fuel in heat and power production, and reduce overall GHG emissions. Also, there is an opportunity to sell excess electricity to the grid.

Figure 3.6: SAGD Central Processing Facility Incorporating Cogeneration

(CESAR 2016) Two cases were analyzed based on partial or full cogeneration. In the partial cogeneration case, an OSTG is replaced with a 43 MW Gas Turbine and Heat Recovery Steam Generator. The Partial Cogeneration process modification is shown in Figure 3.6. Electricity generated is utilized in the central processing facility, and any excess can be sold to the grid. In this case, the cogeneration

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process only provides a portion of the reference case facility's steam requirements, so some steam generation is still required.

The cogeneration process is designed to meet all steam generation and electricity requirements for the reference case in the full cogeneration case. An 88 MW Gas Turbine and Heat Recovery Steam Generator replaces all the OTSGs. Cogeneration through Fuel Cells

Fuel cells generate heat and electricity through an electrochemical reaction. Solid Oxide Fuel Cells (SOFC) and Molten Carbonate Fuel Cells (MCFC) are two high-temperature fuel cell technologies that have the potential to be applied to SAGD operations (see Figure 3.7).

Figure 3.7: MCFC Integration with an In Situ Oil Sands Facility

Source: (Hill, 2015)

Molten Carbonate Fuel Cells convert chemical energy from fuel into heat and electricity. MCFCs consist of an anode and cathode and a molten electrolyte salt layer. Flue gas containing CO2 is delivered to the cathode, and a carbon-containing fuel, usually natural gas, is delivered to the anode. The fuel is reacted with steam over a catalyst through internal reforming at the anode to produce CO and H2 (syngas). CO2 is converted to carbonate ions at the cathode. At the anode, the hydrogen in the syngas reacts with the carbonate ions generated at the cathode and passes through a carbonate electrolyte, producing CO2, water, and free electrons. Electrons' flow from anode to cathode produces an electrical current that can provide power to SAGD operations (CESAR 2016).

Solid Oxide Fuel Cells transfer oxygen ions from the cathode to anode through an oxygen conduction solid electrolyte. SOFCs are operated between 600-1000°C so the oxygen ions can

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cross the ceramic electrolyte. In contrast, MCFCs need a minimum temperature of 600°C to be maintained for the carbonate ions' mobility. For MCFC, CO2 is required on the cathode side to generate carbon ions (McPhail 2011). The process results in almost pure CO2, which can be compressed and sequestered or utilized.

Molten carbonate fuel cell technology can be integrated with existing OTSG to capture CO2 and generate electricity for the operating facility with excess electricity sold to the grid. MCFCs can reduce carbon emissions for SAGD operations while providing low GHG emission electricity to the Alberta grid. The MCFC technology could be adapted to commercial-scale carbon capture (CESAR 2016).

There are challenges with the adoption of fuel cell technology. The manufacturing and materials costs are still relatively high, and scale-up and integration into the existing energy infrastructure has not yet been optimized (NSERC 2013).

Table 3.1: Summary of Steam Generation Technologies

Technology Brief Description Economic Factors Environmental Factors

13% Less GHG emissions Additional investment needed for relative to OTSG. Lower NG the evaporator unit and pumping requirement. Higher requirements efficiency. Two drum process. High Drum steam over OTSG. Requires Ease of operation and Boilers high-quality feedwater. maintenance.

Designed for low-quality feedwater. High steam quality. CAPEX US$1,600 MMBTU/hr Feedwater is heated by working 13% Less GHG emissions. fluid instead of flame. Avoid boiler Lower NG requirement. damage. Reduce Fouling. Higher efficiency.

Dual Loop Dual loop systems work in two loops. First uses Steam combustion to heat a Generation working fluid. Through a Capex US$40,000 MMBTU/hr Larger footprint. heat exchanger, the second loop generates steam from feed water. Feedwater from FWKO DCSG process involves Direct direct contact combusting Eliminates water treatment. Reduces GHG emissions by Contact natural gas with oxygen Untreated produced water. CAPEX 20%. Minimizes freshwater while using water to Steam US$108,00 MMBTU/hr. use. Generation moderate flame temperature.

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Replaces water treatment in a Zero stack emissions. single unit process. Lower CAPEX Produced CO2 is rejected. and OPEX than OTSG. Uses less water and less fuel. High energy requirement for air compression, filtration and NCG separation. Flash Steam Generation Potential to increase water (FSG) heats unprocessed oil recycling rates, reduce GHG sands process water at low Capex US$60,000 MMBTU/hr. Flash boilers emissions and energy pressure to produce high- consumption. quality steam. Feedwater from FWKO No natural gas requirement.

Steam generation from Plasma Fired FWKO using a combination Reduce or eliminate the need of sub-merged plasma arcs Capex US$150,000 MMBTU/hr. Steam for water treatment. Generation and electrical resistive heating.

High indirect GHG emissions due to high electrical load. Feedwater from FWKO PHSG has zero carbon footprint if a green source supplies the electricity. Boiler Allows the blowdown water Additional expenses for evaporator Blowdown to be re-boiled with an Reduce the demand for make- and electricity use have to be taken evaporator without up water by about 50% Reduction into consideration Technology treatment The Economics of fuel cells can Reducing blowdown water improve in situations where the

without treatment. heat and power requirements do not change over time; Depending on the boiler's efficiency and the allocation of gas consumption between Partial Partial replacement of OTSG 43 MW GT + HRSG, US$102.4MM power and heat, up to 19%, with GT+HRSG Cogeneration carbon intensity reduction can be achieved at very high efficiencies. Depending on the boiler's efficiency and the allocation of gas consumption between Full Full replacement of OTSGs 88 MW GT + HRSG. US$209.6MM power and heat, up to 41%, with GT+HRSG Cogeneration carbon intensity reduction can be achieved at very high efficiencies. Electricity is generated Reducing the operating Fuel Cells for directly by chemically temperature requirements can At high temperatures fuel- Cogeneration reacting fuel and oxygen, significantly improve the flexible rather than by combustion economics

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The Economics of fuel cells can improve in situations where the Reduce the cost of carbon

heat and power requirements do capture not change over time;

Source: CERI

3.3 Solvent and Solvent-Assisted Extraction Processes

Historically, solvents have been used in oil operations to reduce oil viscosity, break emulsions, remove asphaltenes, and remove insoluble solids (Gates and Carawat 1971). Current in-situ oil sands projects use solvent only and combinations of solvents and steam processes to reduce the steam to oil ratios (SOR) and improve bitumen recovery. The addition of solvents can also have the added benefits of reducing greenhouse gas emissions, lowering water treatment requirements, and increasing plant capacity by reducing or replacing steam generation requirements. Steam-Solvent Co-injection Processes

In steam-solvent co-injection, a small amount of solvent or a mixture of solvents is injected with steam. Solvent and steam can be co-injected simultaneously or periodically to increase bitumen recovery (Dong, 2018). Solvents injected can range from light, higher volatility hydrocarbons, like butane and propane, to heavier solvents like diluents and naphtha. Solvent selection is dependent on the impact on steam chamber formation, asphaltene precipitation and bitumen recovery, solvent retention in a reservoir, reservoir heterogeneity, solvent cost, and the operator.

One of the major challenges of solvent injection is solvent retention and losses in the reservoir. Actual and predicted pilot solvent recovery ranges have been recorded between actual 33% (Conoco Surmont 101-08 Well Pair) to expected over 95% (Imperial Aspen EBRT Pilot). Solvent recovery is highly dependent on reservoir characteristics, type of solvent, injection and blowdown duration, and blowdown procedure. Jaremko (2018) reported that companies require a recovery percentage of up to 60% recovery for butane and propane and at least 80% for diluent injection to make the economic case for solvent injection.

Inputs used in the supply cost model are from academic and review papers and corporate presentations and documents. Inputs are SAGD-operation dependent and, in most cases, represent a small sample from pilot or demonstration projects.

Expanding Solvent SAGD (ES-SAGD) / Solvent-Assisted SAGD (SA-SAGD)

In Expanding Solvent SAGD (ES-SAGD), also called Solvent-Assisted SAGD (SA-SAGD), a fraction of vaporized solvent is co-injected with steam. The solvent condenses around the interface between the steam chamber, dilutes the oil and, in combination with heat, reduces the bitumen's viscosity

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(Liang 2018). Generally, steam-solvent based processes usually differ by the solvent type and their proprietary deployment and operating mechanisms.

ES-SAGD can enhance recovery by diluting the bitumen by solvent while lowering thermal losses to the overburden by reducing chamber temperatures. Solvents with close thermophysical properties to water and saturation temperatures similar to steam at reservoir conditions are utilized for co-injection.

The solvent-steam co-injection process has been successfully piloted in many in situ projects, most with sustained or improved oil rates, reduced SOR and lower energy and water requirements. The increased drainage rate is sustained by the steam chamber's faster lateral progression.

Solvent-Aided Process (SAP)

In the solvent-aided process, light hydrocarbons, such as methane or propane, are added to steam and are injected at start-up to establish the connection between injector and producer and form an initial chamber. The solvent is then injected with the steam, ensuring the solvent stays in the vapour phase, and moves with the steam to the steam chamber's edge and condenses. Cenovus has been testing SAP since 1996 and piloting since 2002 (Chen 2018). The 2004 Christina Lake (A0101) butane SAP pilot saw a 30% uplift in bitumen rate, 50% reduction in SOR, with 84% solvent recovery. Pure Solvent Injection Processes

Nsolv

Nsolv has a patented technology that involves injecting pure warm solvent in the vapour phase to extract bitumen. A solvent is injected and heated to between 40-60° C through a natural gas heater process at low pressure (500-700kPa) (Liang 2018). The solvent condenses between the warm vapour and cold reservoir, allowing for bitumen's quick dissolution. The solvent is recovered and sent to a distillation column for a purification process.

Nsolv technology is a non-aqueous solvent technology. There is no steam or water treatment required, so the technology reduces the total energy demand, resulting in a capital cost reduction of between 40-50%. GHG emissions also are reduced due to the lower energy demand. The solvent vapour also provides the benefit of partial upgrading in situ. Nsolv reported that the pilot process improved both the produced oil quality and API gravity from 8°API to 13-16°API (Nsolv 2017). The supply cost model assumes a solvent-oil ratio of 3 based on the Nsolv pilot project assessment parameter.

VAPEX

The Vapour Extraction (VAPEX) process is a non-thermal solvent vapour extraction method. Vapour solvent, often propane, is injected at or near the initial reservoir in-situ temperature and

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saturation pressure. The solvent diffuses into bitumen and forms a chamber. This process is based on the assumption that solvent can reduce the bitumen viscosity and mobilize bitumen in the same order as heat (Bayestehparvin 2017). The VAPEX process has a low energy requirement but is slower than typical SAGD processing due to the low diffusion rate of solvent into cold bitumen (Alberta Innovates 2012).

VAPEX can reduce water demand, energy input, GHG emissions, and completion and facility costs compared to conventional SAGD. The VAPEX process can be applied to thin reservoirs due to its nonthermal characteristics. However, oil rates can be low and start-up challenging without the presence of steam.

VAPEX has been piloted with mixed results (Alberta Innovates, 2017). The Dover VAPEX pilot project (DOVAP) was implemented in 2003 and ended in 2008. Results indicated that the process was slow in a cold reservoir, and the concentration of propane in produced bitumen was low. Devon Energy summarizes the results in a 2005 AER submission (Devon Energy, 2005).

However, warm and hybrid VAPEX approaches, such as MEG Energy’s eMVAPEX, that combine heat and mass transfer mechanisms of both solvent and thermal processes are currently being piloted. No results are available yet. Non-Condensable Gas Co-Injection Processes

As steam condenses in the reservoir, the pressure reduces, so co-injection with a non- condensable gas (NCG), such as natural gas (methane) or CO2, helps maintain reservoir pressure and allows steam capacity to be allocated to other wells.

Steam and Gas Push (SAGP)

Steam and Gas Push (SAGP) involves injecting a small amount of non-condensable gas with steam into the reservoir during the SAGD process. Natural gas is the most common non-condensable gas co-injected. Natural gas can also contain a small amount of condensable gas solvents, like propane. These have the added benefit of reducing bitumen viscosity through dissolution.

The injected gases accumulate at the steam chamber's top, reducing heat loss to the overburden. SAGP has been applied to at least eight oil sands projects with positive results indicating improved pressure maintenance, stabilized oil declines, and steam injection ratio reductions. SOR improvement and no negative impact on oil recovery have been observed in almost all SAGP pilots (Liang 2018).

Modified SAGP (eMSAGP)

Modified SAGP, or eMSAGP, is a proprietary recovery process from MEG Energy involving co- injection of non-condensable gas with steam. Infill wells, or collector wells, are drilled between existing SAGD well pairs to improve bitumen recovery (MEG Energy 2019).

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3.4 Other Extraction Technologies and Processes Electromagnetic (EM) Heating Processes

Electromagnetic (EM) heating processes rely on preferential absorption of EM energy as a means of increasing the temperature of dielectric materials (Bera and Babadagli 2015). EM waves exert torques on the polar molecules of water in oil sands. This causes the molecular dipole moments of water to align themselves with the oscillating electric fields of the EM waves. The interactions of oscillating polar molecules with their neighbours generate frictional heat, which raises the medium's temperature (Bera and Babadagli 2015).

Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) Process

The ESEIEH process uses a combination of electricity and solvent to reduce bitumen viscosity. Similar to the SAGD configuration, the ESEIEH process uses horizontal well pairs and a radio frequency (RF) antenna as a heat generation medium. The antenna uses electrical power to produce electromagnetic radiation, which is absorbed by di-electric materials in the oil sands reservoir and consequently heats and mobilizes bitumen. A solvent is added to further reduce viscosity.

The ESEIEH process cost is estimated to be at least 120% of the conventional SAGD plant cost. Expert opinion suggests a value of up to 200 % of the conventional SAGD process depending on the number of wells, antenna lifespan and performance. However, the ESEIEH process has the potential to reduce GHG emissions by 70% (Patterson 2016)

Radio Frequency (RF) XL Process

Radio Frequency heating harnesses the energy contained by an electromagnetic (EM) wave (10 kHz – 100 MHz, corresponding to the RF range), which is indirectly transferred as heat energy to the oil sands reservoir.

The EM heating process directly heats the connate water, which reduces bitumen viscosity. The RF XL process deploys an antenna or applicator that radiates an EM field into an oil-bearing formation (Vaca 2014).

Steam-Surfactant Processes

Surfactants are used in conventional oil recovery to increase recovery by reducing the reservoir's oil/water interfacial tension. Steam-surfactant processes have been piloted by both Cenovus and Suncor with limited success. Cenovus co-injected surfactant at <0.3 wt% of steam in 2014 and stopped in 2015 after results were inconclusive due to interaction with neighbouring wells and thief zones (Cenovus 2016). Suncor is continuing to pilot surfactant at MacKay River.

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Exothermic Chemical Treatment (ECT) ECT technology uses a combination of chemicals called Binary Mixture to heat and pressurize the reservoir pay zone, which leads to an increase in the recovery factor. As shown in Figure 3.8, a liquid solution of chemicals is periodically delivered via a mobile unit platform into the bottom of a well, where an Injection Spearhead is installed. At the Injection spearhead, the Binary Mixture elements react to generate gases (nitrogen and steam) and produce significant amounts of thermal energy, which heats the pay zone, leading to higher reservoir pressure and lower oil viscosity. New Oil Generation develops the techology. It uses the integration of a logging system interconnected with very responsive sensors to keep the chemical reaction under control during the entire operation. As the reaction takes place down at the bottom of the well (bottom hole assembly) and is fully controlled, there are no energy losses during the process. ECT can be operated in a continuous (injection and production) or ‘huff and puff’ mode.

Figure 3.8: Continuous Operating Configuration of the ECT Technology

Source: New Oil Generation NextStream Catalyst Additive NextStream is a post-production partial upgrading technology to reduce diluent requirements for oil sands blending and transportation. NextStream uses a fundamental understanding of the asphaltene fraction in a given oil sands sample to design catalysts that target and modify the asphaltene content associated with the high viscosity of produced bitumen. NextStream is said to reduce bitumen viscosity by around 90%, corresponding to about a 50% reduction in diluent requirements for transportation of the product. This technology also yields an additional value from quality improvements such as ease of refining, residue conversion, VGO increase, TAN and sulphur reduction.

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Table 3.2: Summary of Solvent, Solvent-Assisted, and Other Extraction Technologies

Technology Brief Description Economic Factors Environmental Factors

33-36% SOR Reduction and 35% natural gas use reduction relative to SA-SAGD Uses a combination of Additional C$75.6MM to the SAGD base. 10.8%-38% bitumen steam and solvents for ES-SAGD SAGD base case production uplift. bitumen extraction SAP 15%-20% emissions reduction relative to the SAGD base

75% reduction in SAGD energy SAGD CPF and overall CAPEX A pure condensing intensity. OPEX is similar to that of the were reduced by 50% and solvent is used for SAGD base. No bitumen uplift. Nsolv 30-40%, respectively. bitumen extraction. 75-80% reduction in SAGD direct fuel- C$35,000 per flowing barrel. derived emissions

Vapour solvent is injected into the reservoir as a vapour Vapour phase near the initial Extraction reservoir in-situ No supply cost run. No commercial projects. (VAPEX) temperature and at its saturation pressure. Methane & Propane. Devon

Involves injecting non- CAPEX is similar to Base Co-injection of 1-4 mol% non- Steam and Gas condensable gas Case. Methane taken from condensable gas (methane) (methane) with steam in Push fuel gas supply ~20% emissions reduction relative to the reservoir during the (SAGP) infrastructure. SAGD Base. SAGD process.

MEG Energy's Increase oil recovery 10-12%. SOR Enhanced proprietary process Additional CAPEX 5% ($45 reduction 30-50% lower to 1.3. involves drilling infill Million) to drill additional Modified SAGP A lower steam requirement, reduce wells between producing infill well per well pair. (eMSAGP) GHG emissions 51% wells.

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Chemicals (e.g., Non-energy OPEX of C$5.81/bbl. The surfactants) are added to steam-surfactant process's energy Steam the steam, and the A CAPEX of C$37,000 per intensity is 10-15% less than that of a Surfactant mixture is injected into flowing barrel. SAGD. oil sands reservoirs for Potential to reduce GHG emissions by bitumen recovery 10-15%.

CAPEX similar to pure Reduces energy intensity of the SAGD Uses electromagnetic Electromagnetic solvent except for additional base case by 75%. OPEX is $16.2/bbl heating combined with electromagnetic heating (2016 values). Heating / pure solvents for antenna costs of ~ US$8-10 Potential to reduce GHG emissions by ESEIEH bitumen extraction Million per well-pair 70%

There is no need for steam Uses a chemical mixture generation and water Exothermic Lower GHG emissions and lower to generate heat, treatment units – therefore, Chemical facility footprint. Carbon footprint is pressure and gases, lower CAPEX. However, indirect through electricity Treatment which mobilize the OPEX is quite higher due to consumption (ECT) bitumen in-situ the cost of treatment chemicals

An additional facility is Post-production needed for the process, Higher GHG emission and facility treatment reduces along with more heat footprint than the base facility. NextStream asphaltene content and requirements. Higher CAPEX However, the quality improvement reduces its viscosity and and OPEX, but the product is means a lower footprint at the diluent used. of better quality than raw downstream refining stage bitumen

Source: CERI

3.5 Wells and Well Pads

Drilling in dense sand and carbonate presents unique challenges because the oil is poorly consolidated and sticks to the drilling materials. This increases the cost and delays well completion. During the past ten years, new solutions such as fluid drilling (Halliburton N-solate Packer Fluid System) were used to tackle these challenges resulting in improved drilling operations efficiency. Although bottom line drilling time is optimized, delays are often outside the control of drilling companies and increase drilling costs.

Rather than looking at the technologies delivering incremental efficiencies, this study will target the organizational change inspired by other industries that offer higher efficiencies and reduces the cost of drilling. This section focuses on how lean manufacturing principles apply to drilling operations and how well pads' modularization is a viable option to reduce costs in a volatile oil price environment.

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Lean Manufacturing to Lean Drilling

Lean manufacturing minimizes waste. Implementing lean strategies can identify waste sources during drilling resulting in reduced well completion time. Process organization tools within Lean, such as Pareto diagram, Total Productive Maintenance, 5S, Mistake Proofing (Poka Yoke), are among the principles used to reduce waste, identify improvement opportunities, implement the required changes, and also measure their impacts.

Modularization

During the years of fast growth in the oil sands, the industry faced labour scarcity, delays in project schedules, and cost escalation. Modularization was used to address this challenge and can be used in all the facility segments. Different technologies and vendors are summarized in Table 3.3.

Table 3.3: Summary of Well and Well Pads Technologies

Company Process Area Type of Operation Principal Cost Reduction Achieved Performed Various service Drilling operation Shortening the time to complete well and Lean drilling providers management reduce waste Standardization & Manufactures wellpad 20-50% CAPEX and time reduction Wood Modularization service packages Standardization & Simplified design 40%-50% CAPEX reduction ITS Modularization 40-60% reduction in the cost of building Standardization & Zero-Base Design materials; 35-55% reduction in the overall Cenovus Modularization well pad costs Source: CERI • 3.6 Water and Wastewater Treatment

The water cycle in a SAGD plant is shown in Figure 3.9, showing various processes and technologies that could be deployed for water/wastewater treatment.

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Figure 3.9: Wastewater Treatment and Steam Generation Process

Source: CERI Note: Technologies and processes that are alternatives to each other are represented in the yellow options boxes.

The first stage involves the separation of oil and water. The first oil water separation process is Free Water Knockout (FWKO), in which free oil is removed from the produced water. Then the produced water goes to the skim tank (ST), which uses gravity to separate oil and water further. There are two options further in the oil water separation stage: a combination of Induced Gas Flotation (IGF) and Oil Removal Filters (ORF), or De-oiling (DO) followed by Reverse Osmosis (RO). The conventional plant uses IGF + ORF processes.

Once the oil is removed from produced water, the water enters stage two - wastewater treatment. Wastewater treatment has three options to choose from: Evaporation, a combination of Warm Lime Softening (WLS) + Ion Exchange (IX), or Electrocoagulation. The conventional plant employs WLS + IX processes. Finally, in the third stage, recycled water is used for steam generation. Additional water (make-up water) is added to recycled water if required. All three wastewater treatment processes can include Zero Liquid Discharge (ZLD) to increase water recovery.

Filters are used in every water treatment process configuration. Generally, filtration serves to remove most of the larger-sized or precipitated impurities in the water. The use of filters makes it possible to minimize the need for frequent equipment cleaning and servicing, avoid inefficient performance, and prevent damage to process components.

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The alternative technologies are described in detail below and shown in Table 3.4. Oil and Water Separation

The adoption of efficient, reliable and affordable de-oiling technologies is important for water management in oil sands bitumen production facilities. Processes that are typically used in the oil-water separation step include:

De-oiling

De-oiling is a process that separates oil from water. The Total Oil Remediation and Recovery System (TORR™ System) by ProSep Inc. is a self-cleaning system based on a combination of filtration, coalescence and gravity processes (ProSep 2020). It uses RPA® (Reusable Petroleum Absorbent), which is highly oleophilic and absorbs very fine oil droplets (> 2 microns) and coalesces them, allowing them to float to the top. Water from the outlet treatment contains hydrocarbon well below 5mg/L (Plebon 2002). The system has a low maintenance cost, but the high level of suspended solids induces fouling, thereby increasing operating expenditures (OPEX).

Another technology for de-oiling is from RJ Oil Inc. in collaboration with Alberta Innovates – Energy and Environment Solutions. They developed a high temperature (>120oC) de-oiling technology, eliminating the requirement to lower the temperature of produced water. (Lightbown and Bozak 2015). Since the cooling of produced water before de-oiling is not required, the process's GHG emissions are lower. Wastewater Treatment

Once the oil is recovered, the wastewater is treated to be recycled. This wastewater also includes any make-up water (fresh or brackish) that may be introduced into the process and recycled boiler blowdown water. At this stage, the water contains high amounts of total dissolved solids (TDS 4,026 ppm – 17,200 ppm) ), total organic carbon (TOC 695 ppm – 2,482 ppm) ), silica (65 ppm – 238 ppm), magnesium (0.35 ppm – 0.75 ppm), and calcium (2.8 ppm – 4.5 ppm) (Shamaei et al. 2018; Pillai et al. 2017; Mohammadtabar et al. 2019). As the OTSGs can tolerate high amounts of TDS and TOC from the de-oiled produced water, conventional WLS-IX treatment aims to remove only hardness and silica components. This results in low-quality steam and leads to high operational and maintenance costs due to the fouling and scaling of steam generators (Sadrzadeh, Pernitsky, and McGregor 2018).

Warm Lime Softening (WLS)

Lime softening is used to reduce hardness and silica from de-oiled produced water. In the process, calcium and magnesium ions react with added chemicals that convert them to suspended solids (Toghraei 2013). The suspended particles agglomerate and then settle at the bottom. Generated clear water can then be removed.

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The filtered effluent from the lime softening step goes to ion exchange softeners. Ion exchange softening is recommended whenever raw water hardness exceeds 1 ppm (Lightbown 2015). The ion exchange (IX) softeners remove hardness, preventing scale buildup on the heat transfer surfaces on heat exchangers and the boiler's inner walls helping to maintain more efficient heat transfer.

Adding Dissolved Mg in Warm Lime Softening

In traditional water treatment with lime softening, Magnesium Oxide (MgO or Magox) can be added to process affected water (PAW) to form Mg(OH)2, which adsorbs silica for removal from the water treatment segment. At higher pH, dissolved Mg+2 coming from PAW and process recycle precipitates, thereby reducing the amount of fresh MgO required to remove the same quantity of silica. This processing approach has an estimated result of about 78% reduction in fresh Magox consumption, with up to $1.23 million in annual Magox cost savings (Assumes Magox cost of $600/ton and in situ magnesium concentration of 2 mg/l.).

Elimination of Warm Lime Softening

A study by Bridle (2005) found that with very low concentrations of hardness ions, very little scaling occurs in a normally operating OTSG with a high concentration of silica (350 mg/l) in the feed water. However, the operating guideline for OTSGs used in SAGD operations requires feed water to the steam generator to contain no more than 50 mg/l of silica (Dejak 2016). Produced water in the SAGD process has silica concentrations of 150-350 mg/l and is usually treated by lime softening to reduce silica to below 50 mg/l (Dejak 2016).

The Zero Lime Softening technology by Eco-Tec proposes that lime softeners can be eliminated because the interaction of residual hardness with silica in the OTSG leads to scaling of the boiler. This residual hardness can originate from very fine particles formed in the lime softener, which find their way to the OTSG or impair the ion exchange softener's performance so that hardness leakages occur in the ion exchanger.

The hardness level that allows the elimination of lime softening is reported to be less than 0.1 mg/l (Dejak 2016). The proposed water treatment system would be made up of advanced filtration, which can significantly reduce oil and solids, followed by ion exchange softening. The ion exchange softening can be done in a few softener configurations. However, one advanced form, proven in operation in heavy oil production in California, features advanced brine regenerated Strong Acid Cation/Weak Acid Cation (SAC/WAC) ion exchanger systems, which can reduce hardness to below 0.1 mg/l and magnesium to parts per billion proportions in the boiler feedwater. The boiler blowdown is concentrated with silica (about 200 ppm), which can be used to sequester up to 5% of the CO2 produced in the facility. Overall CAPEX reduction is said to be 30% in WLS cost and OPEX reduction of 30% - 70% in water treatment chemical cost (Eco-Tec 2020) (assuming water treatment constitutes 30% of overall CAPEX).

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Evaporation

Evaporators provide an alternative to the water lime softening based treatment process. Warm lime softening works well with water with a lower total dissolved solids content <7000 ppm (Lightbown 2015). With higher total dissolved solids content, more chemicals are required for the treatment that results in the formation of sludge. This can make the treatment ineffective and expensive as the amount of treated water coming out from the softener decreases. Consequently, very high TDS produced water is better treated using evaporators, and SAGD operators are prioritizing evaporator technologies for silica and hardness removal (Lightbown 2015). Evaporators are known to provide high-quality water treatment while maintaining high water recycle rates, eliminating the potential for fouling in steam generation. Due to high-quality boiler feed water, drum boilers can be used for steam generation, which has lower operational expenses (Heins 2010).

Moreover, seeded slurry evaporative technologies have further optimized basic evaporators for SAGD applications with remnant oil carryover. The benefits of using evaporators are limited to high quality water treatment, and higher recycling rate and lower maintenance and operations cost. However, some challenges with the use of evaporators in oil sands include requiring a large amount of electricity and no need for high-quality water for OTSG (PTAC 2012).

An emerging technology in evaporation is the falling film evaporator, and its variations: vertical tube falling film evaporator and the horizontal falling film evaporator. In falling film evaporators, de-oiled water enters from the top and is evaporated while flowing downwards, forming a continuous thin film along the wall of the evaporator. The liquid film starts to boil due to the heating tubes' external heating. Residual film liquid and vapour are separated in the downstream droplet separator.

The SmartMOD™ evaporator system by Aquatech utilizes a vertical tube falling film evaporation design. This technology has a high heat transfer rate, resulting in efficient steam generation and treating impure produced water. The Horizontal MVC evaporator by IDE Technologies is a horizontal falling film evaporator with multi-stage evaporation that removes salts at each stage. Horizontal orientation improves energy efficiency and makes it easy to clean and maintain.

Zero Liquid Discharge (ZLD)

In SAGD facilities that do not have the option of deep-well disposal of the waste blowdown streams or facilities to achieve stringent water recycling requirements, Zero Liquid Discharge (ZLD) is used to eliminate disposable water streams from the process (Lightbown 2015). Zero Liquid Discharge tries to limit the amount of wastewater that needs to be treated. The common approach to ZLD is to use filtration technology to channel the drained liquid to an evaporator, and the evaporator concentrate can be sent to a crystallizer or spray dryer. The capital and operating costs are higher for ZLD and generate more emissions than the conventional water

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treatment system. However, it has potential as an efficiency improvement and environmental conservation measure.

Electrocoagulation (EC)

Electrocoagulation (EC) is one of several electrochemical techniques for water treatment. It combines the benefits of coagulation, flocculation, and electrochemistry. EC water treatment systems can be used instead of an evaporator or lime softener. The EC process removes the dissolved solids in the produced water by electrically generating the coagulant and floating the sludge using a gas (methane, nitrogen, or hydrogen) instead of the chemicals needed in standard coagulation/flocculation (Moussa et al. 2017). It often uses an iron electrode that ionizes by releasing electrons used to precipitate dissolved ions in the produced water. Larger particles are suspended during the process, which then are easier to remove. EC's advantages include simple equipment, possible automation of the process, no chemicals required, and the production of much less volume of sludge than chemical coagulation. It also consumes less energy than evaporators and is more effective than WLS as it removes sulphide as well (Chow and Pham 2019). However, the anodes need to be replaced as they dissolve in the process (Mollah et al. 2004).

High Temperature Reverse Osmosis (HTRO)

High Temperature Reverse Osmosis (HTRO) is an upcoming oil sands produced water treatment technology that could eliminate the need to lower the temperature of de-oiled water. Current technologies have temperature limitations that do not allow water to be treated at higher temperatures. Since the HTRO technology could eliminate the need to reduce the temperature of produced water prior to water treatment, it could result in a 5-10% reduction in GHG emissions (ERA 2019) and reduce footprint by adopting membrane technology (CNRL 2019).

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Table 3.4: Summary of Water and Wastewater Technologies Wastewater Brief Description Economic Factors Environmental Treatment Process Factors De-oiling: TORR™ Combination of - Lower maintenance filtration, coalescence cost and gravity processes Adding Dissolved Mg Reduction in Magox - 78% reduction in - Reduction of soda in Lime Softening use by adding dissolved fresh Magox ash consumption Mg in the water consumption - No significant treatment process - $1.23 million in reduction in annual Magox cost emissions from saving sequestered CO2 Elimination of Warm Reconfiguration of - 30% reduction in WLS - 10 – 20% overall GHG Lime Softening conventional water cost emission reduction treatment - 30% - 70% reduction from the water in water treatment treatment unit chemicals cost Evaporation Evaporating water - 66% increase in - Produced water from de-oiled water treatment recycle rate over 90% produced water CAPEX through thermal - 46% reduction in processes steam generation CAPEX - Savings in water treatment chemical costs Zero Liquid Using evaporation and - Higher CAPEX - Up to 95% water Discharge (ZLD) crystallization to requirement recovery eliminate the liquid discharge Electrocoagulation Using electrical - Savings in water - Much less volume of (EC) properties to coagulate treatment chemical sludge than chemical and filter dissolved costs coagulation matters - Less expensive than - Lower GHG emission evaporators compared to the conventional water treatment process High Temperature Eliminates the need to - Reduced CAPEX and - 5%-10% reduction in Reverse Osmosis lower produced water OPEX GHG (HTRO) temperature Source: CERI

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3.7 Machine Learning and Artificial Intelligence

Machine Learning (ML) and Artificial Intelligence (AI) are at the forefront of significant change in business practices with potential cost reductions in the range of 13-25% and increases in production in the range of 3-15% (British Petroleum 2015; Edwards 2017; IEA 2017). Possible technology solutions are listed below in Figure 3.10, which illustrates the opportunities areas for implementing digitalization in the in situ sector.

Figure 3.10: Adoption and Implementation of Digitalization in the In Situ Sector

Source: CERI

Veerum

Veerum is combining several recent advances that include asset tracking to digital twin technology and virtual reality to enable lower cost, more efficiently delivered well pad construction projects. This technology utilizes robots and drones, lasers, and photogrammetry to capture a physical site's layout and create a digital twin within tight tolerances. Veerum’s system allows the prediction of asset behaviour and the capacity to deliver within given parameters and cost constraints.

The technology claims to reduce the total wellhead capital costs by ~30%, along with a 43% reduction in site installation costs.

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Ambyint

Ambyint provides artificial lift optimization solutions by leveraging proprietary math-based models. Ambyint deployed Industrial Internet of Things (IIoT)-enabled High Resolution Controllers connected to the Production Optimization Platform for Husky (Ambyint 2018). The system allowed full visibility of well performance in real-time and provided autonomous control. Due to the well sites' remote nature, Ambyint also provided a cost-effective satellite communication module. During the 60 well pilot, Husky realized $900k of annual savings with a two-month payback (Ambyint 2018).

Tachyus

Tachyus provides software-as-a-service (SaaS) for steam flood optimization in oil production. It creates real-time closed-loop reservoir management and cash flow optimization by describing, predicting and prescribing the quantity and placement of injectant fluids required for optimum operations.

The company has a set of applications that optimize fluid injection and cash flows. Two of these, Atmion and Thermion, perform best plugged into mature, brownfield projects with high well count and large quantities of data, or into greenfield with 2-3 years of operational data. The software solutions have helped operators realize an average SOR reduction of 20%, resulting in a production uplift of up to 20%.

General Electric (GE)

GE’s Thermal Production Optimization software uses proprietary Machine Learning (ML) models to create a digital twin of a SAGD project to optimize operations like steam allocation across the field, resulting in costs and environmental savings. The tool allows operators to establish ideal operating parameters on individual wells or across an entire field.

Guild One

Royalty Ledger is the GuildOne's blockchain solution that brings the trust, efficiency, and security of distributed ledgers to oil and gas royalty transactions. Oil and gas royalty transactions are subject to frequent and costly data- and contract-driven disputes, which often entail costly reconciliation. The blockchain-based solution cuts the costly data and contract disputes and allows for a near-instant exchange of value, drastically reducing transaction times and costs.

Real-time steam allocation workflow using ML for digital heavy oil reservoirs

Sibaweihi et al. (2019) presented a case study and proposed a workflow for real-time steam allocation for SAGD multilateral well pad operations. The acquired real-time data from the reservoir is used to build a predictive model using a machine learning approach. Under different scenarios with high, medium and low recovery well-pairs and varying steam availability, the field

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NPV increased 25 – 50%, and the field cumulative SOR decreased between 5 – 15%. However, the analytical model did not integrate granular real-world data attributes from the field. SAS Analytics

SAS software is used for analytics, business intelligence, and data management. Its oil sands in- situ extraction focus areas are asset performance analytics, asset optimization, production optimization, and new field technologies integration assessment.

Both steam generation plants and reservoirs generate a large volume of physics data (temperature, pressure, fluid dynamics, etc.). The model documents this massive data set to extract the information needed to send an optimal volume of steam in the reservoir. A complex model applying a multivariate, machine learning method (random forest) between sub-cool temperature and wellhead pressure is used as a proxy to establish a reservoir production profile. The model is adjusted as reservoir conditions change and for each well. The solution, which is scalable and requires no programming skills, can be an asset to bridge the existing digital knowledge gap in the industry.

SAS’ asset optimization system for in-situ oilsands producers computes optimal steam distribution on a field-wide basis by developing analytical models. It is designed to determine and predict the steam requirements at a field level and forecast events such as steam breakthrough and process upsets.

OPLII

OPLII Calgary is a software company that provides a SaaS solution capable of reducing inspection costs by 40 - 50%. The tool is essentially an operations and asset integrity management platform. OPLII also extends into remote offline areas, allowing field users to conduct inspections, log work- orders and administer projects via smartphones or tablets. This enables operators to control sites, facilities, equipment, inspections, work orders, projects, Health Safety and Environment (HSE) and maintenance, among others. The key features include dashboard Key Performance Indicators (KPIs), easy material transfers and powerful quick-searching capability.

Fotech

Fotech has two applications for well integrity and pipeline integrity management. For well integrity, an optic fibre is placed in the well and provides a continuous acoustic profile. The optic fibre can detect casing breaches, tube and bypass leaking and cement casing fractures. This technology's primary output is real-time intelligence of the well and downhole tools. It also informs the operation team where to concentrate the steam injection effort for the most production. It reacts in real-time to sand inflow and leak detection, limits downtime and updates reservoir seismic data.

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Vista Projects

Aveva Net by Vista Projects is a portal that provides a project database with real-time updating features for sharing by all parties involved in the project. The Aveva Net platform claims a ~10% reduction of total installed costs and a 15 – 40% reduction of engineering costs.

The expected capital cost reduction reported by Vista Projects is 20% relative to baseline due to minimizing handover costs, compressing the project schedule and improving project execution. The engineering team delivers efficiency improvements by simplifying the process, allowing for simultaneous electronic team check-ins and providing data-centric progress tracking and digital approvals.

Applications for AI in Reservoir Engineering

Evidence of AI applications in reservoir engineering in the in-situ oil sands is missing. However, academic literature shows some potential for applications of deep learning techniques for reservoir characterization and estimating changes in reservoir properties over the course of SAGD production.

Ma (2018) discusses data-driven models and a set of workflows suitable for predicting SAGD production performance and inference of heterogeneities through data analytics and production data analysis. The models were built as a proxy model of the conventional reservoir simulation process using deep learning techniques to approximate the forward relationships between SAGD production and reservoir parameters. However, the models were not trained on field datasets. They had limited discussion on quantitative gains on process efficiencies, CAPEX and OPEX reduction, reduced computational costs, or time savings due to faster decision making.

Tiwari, Roy, and Cardozo (2018) discussed a ML and data-driven approach to interpreting 4D seismic data to monitor the steam chamber growth during SAGD operation. The model also quantified reservoir properties changes in the reservoir over time, ultimately allowing to determine patterns and predict unknown or future events.

Table 3.5: Summary of Prospective Digital and AI Technologies Principal Cost Reduction Company Process Area Type of Operation Achieved or Environmental Benefit Wellhead capital costs Well pad Digital Twin – asset information and reduction by 30%, and site Veerum construction visualization platform installation costs reduction by 43%

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IIoT-enabled High Resolution Well Controllers that connect to the optimization Production Optimization Platform $900k of annual savings on a Ambyint and automation and allow for full visibility of well 60-well pilot solutions performance in real-time, and provide autonomous control. Thermion solution. Empowers operators to prioritize the best cyclic Cyclic Steam steam candidates by ranking all 20% increase in oil production; Tachyus Optimization opportunities in the field and solving up to 50% decrease in SOR for the optimal stimulation volume on a per job basis Atmion solution. Fluid injection and Steam flood flow optimization using machine Tachyus and heat learning and fundamental 20% reduction of SOR management physical principles found in traditional reservoir simulators. Uses proprietary machine learning General Production models to create a digital twin of the 1-5% increased production Electric (GE) optimization SAGD project to optimize steam allocation across the field Elimination of 30 - 80% of the effort (equivalent to 1 FTE per Royalty Guild One's Royalty Ledger solution annum) associated with royalty calculations and Guild One using distributed ledger/blockchain calculations, payments and payments entries into ledgers and subsystems Steam injection Real-time steam allocation workflow Sibaweihi et al for heavy oil using ML for digital heavy oil 5-10% SOR reduction reservoirs reservoirs Analytical models can compute Asset Additional 40 bbls/d production optimal steam distribution on a field- SAS Analytics optimization per producing well wide basis. Predictive Predicting asset failures and 70% downtime reduction SAS Analytics maintenance reducing downtime Production Steam flood injection optimization 7-15% production uplift SAS Analytics optimization Inspection and OPLII operations Connecting fields with the office 40-50% inspection costs management Acoustic optic Well and pipeline integrity Reduction of OPEX Fotech fibre sensor Digital Synchronize and shared database for 16% reduction of front end engineering Vista project project front end engineering design engineering design environment Source: CERI

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: Supply Costs and GHG Intensities

• Overall supply costs could be reduced by C$5 – C$7/bbl with a potential to achieve a total reduction of C$10 – C$11/bbl if solid oxide fuel cells and eMSAGP prove viable. • Many of the newer technologies increase supply costs due to higher capital costs or, in the case of solvent and solvent-assisted process, the cost of lost solvents. • Overall GHG intensity could be reduced, depending upon configurations, by 15 – 20 kg CO2e/bbl with the potential to achieve a total reduction of 42 – 47 kg CO2e/bbl if solid oxide fuel cells and some solvent technologies prove viable. • There is a subset of newer technologies and processes that lower the supply cost below the Base Design’s C$41/bbl and GHG emissions intensity below 61 kg CO2e/bbl (Figure 4.1). The largest reductions are associated with either improved steam generation technologies or solvent and solvent-assisted technologies.

Supply costs and GHG intensities for a typical SAGD in situ facility have been determined to be C$40.61/bbl as described in Chapter 2. The GHG intensity for this reference facility has also been determined to be 60.97 kg CO2e/bbl. This is referred to as the Base Design for this study's purposes.

For reference, the Base Plant design is based upon:

• Cumulative SOR of 3,

• OTSG steam generation at an assumed efficiency of 80% producing high pressure (12 barg) dry steam,

• Employs free water knock-out and mechanical treaters for oil treating and warm lime softening for water treatment.

The results shown in Table 4.1 and Table 4.2 are obtained by applying emerging technologies in the process assessed but keeping other processes consistent with the base SAGD Base Design. This can mean simply substituting one steam generation technology for another, while in other cases, additional changes were required. For example, SA-SAPG or SAP technologies' application leads to a 50% reduction of the central processing facility because water treatment and steam generation facilities are almost eliminated. But, newer equipment for heating solvent to approximately 60oC is needed.

Note that to compare technologies in this report, the results shown in Table 4.1 and Table 4.2 have been rounded to C$1/bbl and 1 kg CO2e/bbl. This has been done to recognize the fact:

• The data used in this report are based on publicly available information for technologies close to, but not yet commercially proven, and

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• Broad assumptions have been made about other plant scope changes, i.e., how much does adopting a solvent technology change the need for water treatment facilities? Supply Cost

Referring to Table 4.1, many of the newer technologies increase supply costs due to higher capital costs or, in the case of solvent and solvent-assisted process, the cost of lost solvents. Newer boiler designs and the solvent-based SA-SAGP and SAP processes lower supply costs by C$1 – C$3/bbl. Solid oxide fuel cells and the solvent eMSAGP process are shown to lower supply costs by C$6 – C$7/bbl and offer sufficient potential to warrant CERI following the development of both of these in addition to the solvent process in general. Focusing on improved wells and well pads through standardization and modular construction, improved Water and Wastewater Treatment, and Machine Learning and Artificial Intelligence each have the potential to reduce supply costs by C$1/bbl.

Thus, overall supply costs could be reduced by C$5 – C$7/bbl with a potential to achieve a total reduction of C$10 – C$11/bbl if solid oxide fuel cells and eMSAGP prove viable.

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Table 4.1: Summary of Technology/Process on Supply Cost & GHG Intensity (Ranked by Supply Cost)

Base Design $41 61 Contributions to Supply Cost Supply Cost GHG Intensity Process/Technology Abbreviation CAPEX (C$/bbl) OPEX (C$/bbl) (C$/bbl) (kg CO2/bbl) Steam Generation SG Solid Oxide Fuel Cells SOFC $34 22 19 7 Dual Loop DL $38 53 18 11 Flash Boiler FB $39 51 19 11 Direct Contact Steam Generation (Oxygen) DCSG $41 49 19 12 Drum Boiler DB $42 53 20 12 Partial Cogeneration with OTSG1 Partial Cogen - OTSG1 $43 59 20 13 Full Cogeneration Full Cogen $45 60 22 12 Plasma Heated Steam Generation PHSG $48 Indirect Emissions 20 18 Solvent and Solvent-Assisted Processes SaSAP Modified Steam and Gas Push eMSAGP $35 30 18 8 Solvent Assisted - Steam and Gas Push (High NCG2) SA-SAGP (High NCG2) $39 49 19 11 Solvent-Aided Process SAP $39 46 17 15 Liquid Addition to Steam for Enhancing Recovery LASER $42 49 20 13 Expanding Solvent SAGD3 / Solvent Assisted SAGD3 ES-SAGD3 / SA-SAGD3 $42 12 20 12 Solvent Assisted - Steam and Gas Push (Low NCG2) SA-SAGP (Low NCG2) $43 41 19 11 Nsolv Nsolv $46 3 16 21 Solvent-Aided Process - Low Concentration Pilot SAP - LCP $48 54 20 12 Other Extraction Technologies and Processes OET Exothermic Chemical Treatment ECT $36 Indirect Emissions 15 13 Nextstream Catalyst Additive NextStream $46 64 20 16 Chemical Additive - Surfactants Surfactant $48 54 19 20 Enhanced Solvent Extraction Incorporating Electromagnetic Heating ESEIEH $71 Indirect Emissions 27 29 Wells and Well Pads WWP Standardization & Modularization S&M $40 61 18 12 Zero-Base Design (Cenovus) ZBD $40 61 18 12 Water & Waste Water Treatment W&WWT Electrocoagulation EC $40 57 19 12 Zero Lime Softening ZLS $40 61 19 12 Warm Lime Softening + Magnesium Addition WLS-Mg $40 61 19 12 Evaporation Evap $41 60 19 12 Zero Liquid Discharge ZLD $42 60 19 13 Machine Learning and Artificial Intelligence ML/AI Thermion Tachyus $35 49 17 11 Atmion Tachyus $36 51 17 11 Asset Optimization SAS Analytics $38 55 18 12 Multiple technologies Veerum $40 61 18 12 Production Optimization SAS Analytics $40 59 19 12 Thermal Production Optimization GE $40 59 19 12 Aveva Net Vista Projects $40 61 19 12 OPLII OPLII Calgary $41 61 19 12 Industrial Internet of Things (IIoT) Ambyint $41 61 19 12 (1) Once Through Steam Generator (2) Non-Condensable Gas (3) Steam Assisted Gravity Drainage

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GHG Emissions Intensity

Most of the newer technologies decrease the GHG intensity, as shown in Table 4.2. Direct contact steam generation and newer boiler designs (Flash Boiler, Dual Loop, and Drum Boiler) reduce GHG emissions intensity by 8 – 12 kg CO2/bbl. Those solvent and solvent-assisted processes with a supply cost equal to or lower than the Base Design reduce GHG emissions intensity by 12 – 31 kg CO2/bbl. In light of the focus on climate change and reducing GHG emissions by the public in Canada and globally, that incremental reduction is reason alone to continue developing these technologies.

Wells and Well Pads and Water and Wastwater Treatment technologies could lead to minor (i.e., none to 4 kg CO2/bbl) improvements. Machine Learning and Artificial Intelligence offer a range of reductions from none to 12 kg CO2/bbl based on improved production and steam/energy utilization, thus warrant further review and follow up given the potential reductions they offer.

Focusing on improved wells and well pads through standardization and modular construction, improved Water and Wastewater Treatment, and Machine Learning and Artificial Intelligence each have the potential to reduce supply costs by C$1/bbl.

Thus overall GHG intensity could be reduced, depending upon configurations, by 15 – 20 kg CO2/bbl with the potential to achieve a total reduction of 42 – 47 kg CO2/bbl if solid oxide fuel cells and some solvent technologies prove viable.

Table 4.3 compares field supply costs per barrel of bitumen and diluted bitumen (dilbit) to demonstrate the impact of quality improvement via partial upgrading of the product by such processes as Nsolv and NextStream. Nsolv reduces dilbit supply cost relative to the base design by about C$3/bbl, whereas NextStream reduces the supply cost by about C$4/bbl.

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Table 4.2: Summary of Technology/Process on Supply Cost & GHG Intensity (Ranked by GHG Intensity)

Base Design $41 61 Contributions to Supply Cost Supply Cost GHG Intensity Process/Technology Abbreviation CAPEX (C$/bbl) OPEX (C$/bbl) (C$/bbl) (kg CO2/bbl) Steam Generation SG Solid Oxide Fuel Cells SOFC $34 22 19 7 Direct Contact Steam Generation (Oxygen) DCSG $41 49 19 12 Flash Boiler FB $39 51 19 11 Dual Loop DL $38 53 18 11 Drum Boiler DB $42 53 20 12 Full Cogeneration Full Cogen $45 59 22 12 Partial Cogeneration with OTSG1 Partial Cogen - OTSG1 $43 60 20 13 Plasma Heated Steam Generation PHSG $48 Indirect Emissions 20 18 Solvent and Solvent-Assisted Processes SaSAP Nsolv Nsolv $46 3 16 21 Expanding Solvent SAGD3 / Solvent Assisted SAGD3 ES-SAGD3 / SA-SAGD3 $42 12 20 12 Modified Steam and Gas Push eMSAGP $35 30 18 8 Solvent Assisted - Steam and Gas Push (Low NCG2) SA-SAGP (Low NCG2) $43 41 19 11 Solvent-Aided Process SAP $39 46 17 15 Liquid Addition to Steam for Enhancing Recovery LASER $42 49 20 13 Solvent Assisted - Steam and Gas Push (High NCG2) SA-SAGP (High NCG2) $39 49 19 11 Solvent-Aided Process - Low Concentration Pilot SAP - LCP $48 54 20 12 Other Extraction Technologies and Processes OET Chemical Additive - Surfactants Surfactant $48 54 19 20 Nextstream Catalyst Additive NextStream $46 64 20 16 Exothermic Chemical Treatment ECT $36 Indirect Emissions 15 13 Enhanced Solvent Extraction Incorporating Electromagnetic Heating ESEIEH $71 Indirect Emissions 27 29 Wells and Well Pads WWP Standardization & Modularization S&M $40 61 18 12 Zero-Base Design (Cenovus) ZBD $40 61 18 12 Water & Waste Water Treatment W&WWT Electrocoagulation EC $40 57 19 12 Evaporation Evap $41 60 19 12 Zero Liquid Discharge ZLD $42 60 19 13 Zero Lime Softening ZLS $40 61 19 12 Warm Lime Softening + Magnesium Addition WLS-Mg $40 61 19 12 Machine Learning and Artificial Intelligence ML/AI Thermion Tachyus $35 49 17 11 Atmion Tachyus $36 51 17 11 Asset Optimization SAS Analytics $38 55 18 12 Production Optimization SAS Analytics $40 59 19 12 Thermal Production Optimization GE $40 59 19 12 Multiple technologies Veerum $40 61 18 12 Aveva Net Vista Projects $40 61 19 12 OPLII OPLII Calgary $41 61 19 12 Industrial Internet of Things (IIoT) Ambyint $41 61 19 12 (1) Once Through Steam Generator (2) Non-Condensable Gas (3) Steam Assisted Gravity Drainage

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Table 4.3: Comparison of Technology/Process Supply Costs on Bitumen and Dilbit Bases

Base Design $41 $49 Supply Cost Supply Cost Process/Technology Abbreviation (C$/bbl) (C$/bbl dilbit) Steam Generation SG Solid Oxide Fuel Cells SOFC $34 $43 Dual Loop DL $38 $47 Flash Boiler FB $39 $47 Direct Contact Steam Generation (Oxygen) DCSG $41 $50 Drum Boiler DB $42 $50 Partial Cogeneration with OTSG1 Partial Cogen - OTSG1 $43 $51 Full Cogeneration Full Cogen $45 $53 Plasma Heated Steam Generation PHSG $48 $57 Solvent and Solvent-Assisted Processes SaSAP Modified Steam and Gas Push eMSAGP $35 $44 Solvent Assisted - Steam and Gas Push (High NCG2) SA-SAGP (High NCG2) $39 $47 Solvent-Aided Process SAP $39 $48 Liquid Addition to Steam for Enhancing Recovery LASER $42 $50 Expanding Solvent SAGD3 / Solvent Assisted SAGD3 ES-SAGD3 / SA-SAGD3 $42 $51 Solvent Assisted - Steam and Gas Push (Low NCG2) SA-SAGP (Low NCG2) $43 $51 Nsolv Nsolv $46 $46 Solvent-Aided Process - Low Concentration Pilot SAP - LCP $48 $57 Other Extraction Technologies and Processes OET Exothermic Chemical Treatment ECT $36 $44 Nextstream Catalyst Additive NextStream $46 $45 Chemical Additive - Surfactants Surfactant $48 $57 Enhanced Solvent Extraction Incorporating Electromagnetic Heating ESEIEH $71 $79 Wells and Well Pads WWP Standardization & Modularization S&M $40 $48 Zero-Base Design (Cenovus) ZBD $40 $49 Water & Waste Water Treatment W&WWT Electrocoagulation EC $40 $48 Zero Lime Softening ZLS $40 $48 Warm Lime Softening + Magnesium Addition WLS-Mg $40 $49 Evaporation Evap $41 $49 Zero Liquid Discharge ZLD $42 $50 Machine Learning and Artificial Intelligence ML/AI Thermion Tachyus $35 $44 Atmion Tachyus $36 $44 Asset Optimization SAS Analytics $38 $46 Multiple technologies Veerum $40 $48 Production Optimization SAS Analytics $40 $48 Thermal Production Optimization GE $40 $48 Aveva Net Vista Projects $40 $49 OPLII OPLII Calgary $41 $49 Industrial Internet of Things (IIoT) Ambyint $41 $49 (1) Once Through Steam Generator (2) Non-Condensable Gas (3) Steam Assisted Gravity Drainage

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Summary of Selected Technologies/Processes

Referring to Figure 4.1, it can be seen that there is a subset of newer technologies and processes that lower the supply cost below the Base Design’s C$41/bbl and GHG emissions intensity below 61 kg CO2/bbl. The largest reductions are associated with either improved steam generation or solvent and solvent-assisted technologies. Note that only for illustrative purposes, Figure 4.1 has omitted the ESEIEH technology, which has the highest supply cost.

Technology and process developers continue to assess and try to improve their technologies and processes to reduce supply cost and GHG emissions intensity, noting that the applicability of any specific technology depends upon individual reservoir characteristics.

Figure 4.1: Summary of Selected Technologies/Processes on Supply Cost & GHG Intensity

Base Design GHG Intensity

Base Design Supply Cost

Source: CERI Note: The number preceding each technology/process is for plotting proposes only

January 2021 64 Canadian Energy Research Institute : Uncertainties and Limitations

• Bitumen reservoirs’ characteristics vary significantly across Alberta and within any specific reservoir. • Applicability and performance of any in situ extraction process is dependent upon the characteristics of the specific reservoir. • Applicability and performance of any water and wastewater treatment technologies is impacted by the quality of the water and solid materials contained within the reservoir.

While many promising technologies are moving towards full-scale deployment in the next five to seven years, caution must be used when assessing the utility and potential of these technologies. Despite thorough research and piloting efforts, various uncertainties and limitations exist.

Uncertainties

The applicability and performance of any in situ extraction process is dependent upon the characteristics of the specific reservoir. Additionally, the applicability and performance of any water and wastewater treatment technologies are impacted by the quality of the water and solid materials within the reservoir.

Bitumen reservoirs’ characteristics vary significantly across Alberta and within any specific reservoir. While a ‘typical’ bitumen reservoir is considered to consist of 10% bitumen, 5% water, and 85% solid material, variations are common in:

• Bitumen content and quality – typically 10% but can be as high as 20%; • Water content and composition – typically a mixture of soluble sodium, potassium, and calcium ions in addition to chlorides and sulphates; • Solids content and composition – typically a mixture of quartz silica sands that include varying amounts of potassium feldspar and the distribution of clays throughout the reservoir, whether dispersed or concentrated in discrete bodies; • The reservoir's physical size includes its thickness and areal distribution, homogeneity, and cap and basement rock integrity.

Given these uncertainties, the results and analysis included within this report provide an overview of emerging technologies. These results cannot be relied upon for use within any specific reservoir until the specific characteristics are known and accounted for in further assessment and analysis. Limitations

This report is based on known technologies described in publicly available information and interviews with both technology vendors and industry personnel. The technologies have been assessed to be at an advanced stage of development. They are at the late development stage,

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typically characterized as a Technology Readiness Level (TRL) 6, or early deployment stage (TRL 7). These technologies can reasonably be foreseen to be commercially and technically viable within five years.

Each asset is unique – there can be wide variability in the realized economic and GHG savings at a field level due to digital technologies’ deployment. Field demonstrations and transparent and evidence-based framework must be used to establish the specific performance metrics of different options to realize benefits at scale.

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