CHOA 35th Anniversary Journal-Edition 1

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October 2021





LEANING IN ON ENERGY TRANSFORMATION It is my pleasure to introduce you to the first issue of the CHOA Journal 35th Anniversary Edition, a whole new look, jam-packed with context and technical articles. Just like other 35-year-olds, we can’t help but be proud of our accomplishments, but we know deep down it’s less about what we did yesterday and more about where we are going. We are driven to make a difference, to do our part to create a prosperous future for our industry. We owe it to our members, our sponsors and society. Our vision is for Canada to be the most responsible and innovative energy resource developer in the world. We exist to strengthen the Canadian energy sector and accelerate the careers of our members. We do this by providing educational, technical, and social programs to expand knowledge, relationships and influence within the heavy oil and oil sands community.

Overcoming obstacles and navigating the terrain ahead – in my spare time

What makes us so great? We are a practical organization focused on lessons learned and finding actionable pathways forward. Our tagline – Connect. Share. Learn. Lead. – is a testament to our values and the reputation we’ve earned connecting individuals and businesses within the changing energy ecosystem. A big thank you to everyone – volunteers, authors, advertisers and sponsors – for your contributions and support in making the Anniversary Series happen. Please drop us a note if reading this triggers a content suggestion. We have three more issues planned: December 2021, February 2022 and April 2022.

In case you didn’t know, it’s sponsorship and membership renewal season. We would not be able to do our part without your support. Please take a moment to visit our website and join us to experience all that we have to offer.

“It’s less about what we did yesterday and more about where we are going” Let’s transform our industry!

Stronger. Together. With energy, Caralyn Bennett


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OCTOBER 2021 October 2021 CHOA.AB.CA


Many thanks to our volunteers on the Editorial Committee, the GLJ layout team, and the CHOA office team for their efforts and contributions to this Journal.

Statements and content herein are those of the authors and contributors, and do not necessarily reflect the views of CHOA, the editors, or organizations with which the authors or contributors may be affiliated. Dissemination of information by CHOA does not indicate CHOA’s endorsement of any product, technology, strategy or company presented herein.

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Celebrating CHOA along with our MEMBERS, VOLUNTEERS and SPONSORS

It’s a BIG DEAL We’re 35 and we wouldn’t be here without YOU! Here’s to our shared future. Transforming energy, making a difference. En route to Canada becoming the most responsible and innovative energy resource developer in the world. We are STRONGER, TOGETHER!

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To Members of the Canadian Heavy Oil Association, Congratulations on your 35th anniversary. Over the past 35 years, you have dedicated yourselves to continuous innovation, persevered through the ups and downs, and have helped create a world-leading energy sector. Not only are you leaders providing responsible energy to people around the world, but you have helped the industry meet ambitious emission reduction targets, and will continue to in years to come through new technologies and transformative cleantech innovations. We know how essential trade associations are to the ongoing development of Canada’s energy sector. Earlier this year, our association expanded our advocacy mandate to include hydrogen, helium, geothermal, and CCUS sectors, in addition to our traditional oil and gas industry. Our history proves that when we work together, we are capable of amazing things, and we recognize the importance of embracing emerging resources while celebrating the accomplishments of our past. With an energy transition well underway, we will work closely to advocate on behalf of our industry. Canada’s energy sector provides hundreds of thousands of good jobs, and contributes to our economies from coast to coast to coast. We will move the dial to make natural resource development even more sustainable to meet climate targets, while providing economic opportunities and long-term growth. Once again, congratulations on all you have accomplished and we look forward to collaborating to meet the energy needs of the future.

Mark Scholz President and CEO Canadian Association of Energy Contractors

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“Since the beginning, the CHOA has continuously developed, engendering a consistent, positive impact on the heavy oil industry...”


From the Beginning: Connecting and Sharing

Since its inception in 1986, the Canadian Heavy Oil Association (CHOA) has been a volunteer-driven, non-profit organization assisted by limited administrative staff (currently 1 person). In 1987, the CHOA was incorporated through the Alberta Societies Act with its first president, Mr. Ken MacKay.

In the 80s the primary objective of the CHOA was to encourage and facilitate direct communication between technical and business development people in the heavy oil industry of the north and north-east of plains Alberta and the western and northwest plains of Saskatchewan. Members were predominantly engineers from commercial producers that were using technology limited to Cold Heavy Oil Production with Sand (CHOPS) and Cyclic Steam Stimulation (CSS), and members from experimental organizations researching new technologies for in situ bitumen extraction, members from Engineering, Procurement, and Construction Management (EPCM) service companies, and members from the regulatory sector. In addition, membership was not restricted to those with professional status. The initial advantage the CHOA provided its members was a new opportunity to share non-confidential technical, operational, and commercial knowledge toward future development of the vast resources of Lloydminster heavy oil and of the Athabasca oil sands.

Since the beginning, the CHOA has continuously developed, engendering a consistent, positive impact on the heavy oil industry , the various professions within the CHOA membership, and the overall well-being of Canada’s energy supply. Many changes within our Association were the result of visionary volunteer members who recognized and acted upon opportunities to provide new or better contributions to Alberta’s heavy oil and oil sands industry and to the professional and social interaction of CHOA members.

“Since its inception in 1986, the CHOA has reliably facilitated informal communication and development of relationships between industry workers, and this has directly contributed to the dramatic increase in proved reserves, resources, and the certainty of Canada’s energy supply – a tremendous societal advantage.” Game-Changing Technologies In the 90s the heavy oil industry of western Canada was impacted by two major technologic advances. First, the subsurface development of horizontal (HZ) drilling technology and successful thermal extraction of bitumen with Steam Assisted Gravity Drainage (SAGD) at the Underground Test Facility (UTF). Then second, by successfully drilling HZ wells from surface into the shallow Athabasca oil sands and successful deployment of SAGD thermal technology for extraction of bitumen from the reservoir (in situ) to surface. SAGD pilot production and then commercial production was proven by Alberta Energy Co. (AEC, now Cenovus Energy Ltd.) at Foster Creek, by Gulf Canada (now ConocoPhillips Canada Ltd.) at Surmont, by PanCanadian Petroleum Ltd. (now Cenovus) at Christina Lake, Petro-Canada (now Suncor Energy Inc.) at MacKay River, and by JACOS at Hangingstone. As a result of this proven subsurface thermal technology and new source of production, CHOA membership grew and reflected multiple industry disciplines. CHOA volunteers saw an advantage: the opportunity to provide members with views and perspectives from the full range of professions essential to the growth of the heavy oil industry. The CHOA welcomed them, and its membership grew in number and diversity. The advantage was that in addition to shared engineering knowledge, CHOA members received benefits of knowledge from the drilling, geoscience, transportation, and marketing segments of the heavy oil business. Oil Sands In Situ Kickoff During the 2000s, the CHOA membership grew in response to high energy prices and significant new investment in the Athabasca oil sands. In response to the growing needs of membership and the heavy oil industry, volunteer Directors on the CHOA Board of Directors (BOD) designed and built the robust 2007 Strategic Plan to ensure the CHOA’s continued relevance and service to its members as they rose to meet the challenges of the next decade. The CHOA BOD was formed in 1991. Historically, the BOD had operated as a working board with individual directors responsible for specific portfolios like “membership and social events” e.g. Golf Tournament, “technical meetings” e.g., Beer and Chat, “Special Events” e.g. Slugging It Out (SIO); and with three executive directors responsible for governance. The foundation of the new Strategic Plan was a fundamental change and became the CHOA’s current organizational structure. The new structure was comprised of a volunteer BOD responsible for governance and of several volunteer Committees and Committee Chairs with responsibility for operation of CHOA services to its members.

Governance goals of the new BOD included membership demographics, sustained value to members, communications (internal and external), non-partisan industry advocacy, financial sustainability, marketing (internal and external), international awareness, regional chapters, and review of the Association’s progress. Advantages the CHOA realized with its new structure of BOD governance and Committee operations were that the BOD defined and then supported operational goals that were consistent with the CHOA mission and with the business environment of the heavy oil and oil sands industry. An additional advantage was the increased capacity for more focused and effective communication of the CHOA BOD with high-level industry stakeholders like regulatory administrators, government Ministers, and corporate leaders. The Journal is Born In 2010 the venerable single-page CHOA newsletter, “The Tarpaper”, printed on newsprint, was replaced by the first issue of the Journal of the Canadian Heavy Oil Association (the Journal). Under the visionary and tenacious leadership of Deborah Jaremko (professional journalist and previous CHOA Director), the Journal became a publication of professional standard. The volunteers of the Journal’s Editorial Committee published an increased variety of heavy oil and oil sands subject matter of strong relevance to the membership. New content included introduction of high-level industry articles, technical articles, real-time updates of producing and pre-production heavy oil and oil sands projects authored by operating companies, interviews of provincial Energy Ministers, social-impact articles, featured professional profiles of individual members, and exposure for CHOA sponsors and corporate members via full-colour advertisements and sponsored content. With 2015 came a dramatic fall in the selling price of oil, for the heavy oil and oil sands sector, exacerbated by a lack of transportation egress and large heavy-light oil price differentials. This was accompanied by unfavourable changes in the Journal publication agreements and costs. As a result of these factors, continued hard copy publication of the Journal became untenable. However, CHOA volunteers stepped up and changed the Journal from a member only, glossy paper publication with a digital archive, to a digitalonly publication available to any interested person via widespread use of the internet. Our membership benefited from continued access to the high-quality and current information in the Journal, opportunity to showcase high caliber professional publications and access to the real potential for world-wide exposure of Canadian heavy oil expertise.

COVID 2020 brought on the Covid Pandemic and the world shut down. Face-toface interaction ceased. Remote communication through the internet became the business and social norm. Once again, the volunteers of the CHOA stepped up with characteristic agility. Within weeks the CHOA was completely digital. Communication of the BOD, the CHOA office, and committees moved to electronic platforms. Plans for CHOA events like technical meetings and conferences were re-planned to become digital events with remote participation of delegates and presenters. CHOA members were able to continue informal networking, technical discussion and sharing of non-confidential information. In addition, the digital format allowed members to view CHOA events like the “Slugging It Out” conference later. Looking Forward Since the late 1990s, the widespread deployment of SAGD in the Athabasca oilsands as a technical and economically viable mechanism to recover in situ bitumen too deep for mining has dominated growth in the heavy oil and oil sands industry. The CHOA has made essential contributions to SAGD deployment and improvements by promoting and facilitating technical interaction between members, industry professionals, disciplines, and industry organizations.

CHOA events like the Fall Business Conference, “Slugging It Out” (a CHOA joint conference with the Petroleum Society of the CIM, now SPE), afternoon Technical Meetings (previously the Beer & Chats), and social functions like the CHOA Lobster Night, have been vehicles of personto-person interaction. Since its inception in 1986, the CHOA has reliably facilitated informal communication and development of relationships between industry workers, and this has directly contributed to the dramatic increase in proved reserves, resources, and the certainty of Canada’s energy supply – a tremendous societal advantage. CHOA members live and work in the volatile business environment of the oil patch. Our professions and employers are subject to ballistic rises and meteoric falls in the investment community’s perception of the economic and social value of heavy oil and oil sands resources. Regardless, even with the industry ups and downs, it has remained that there are numerous opportunities for technical contributions and professional networking in the CHOA. In conclusion, throughout the 35 years of CHOA history, its volunteers have recognized and initiated changes necessary to have a positive impact on the workers and professions of the heavy oil and oil sands industry. If you are passionate about making a difference in our industry as it adapts and transforms in an evolving business environment, to building Canadian energy supply and the social stability energy provides, and to creating real pathways forward, the CHOA is the place to be .

CONNECT. SHARE. LEARN. LEAD. Gordon Stabb, P. Geo. Gordon Stabb is a Petroleum Geologist with a 40-year professional background in Western Canadian oil and gas exploration, development, and production. His expertise includes stratigraphic analysis in siliciclastics, carbonates and business development, in oil sands, conventional oil, EOR, and natural gas. Specialized in oil sands, with integrated interpretation of geologic, geophysical, and engineering information into prospect recommendations. Noted for generating solutions and discoveries that develop profitable projects through coordination with interdisciplinary and operational teams. Gordon’s 22-year volunteer contribution with the CHOA includes: 2010 to 2021: Technical Editor, Journal of the Canadian Heavy Oil Association 2008 to 2010: Board of Directors, Chairman of Technical Committees 2005 to 2008: Chairman, Reservoir and Production Technical Committee 1999 to 2005: Volunteer, Reservoir and Production Technical Committee

IS “VOLUNTEERSHIP” EVEN A WORD? As a CHOA volunteer, you give AND you get. Contribute to delivering CHOA content or events. Grow your network, through doing with others. Play your part in leading toward our industry’s future. Get paid big bucks. Contact us now at CHOA.AB.CA or OFFICE@CHOA.AB.CA


Design. Construct. Deliver. Industry leaders turn to Fluor to provide professional and technical solutions on the world’s toughest projects. In response, we provide solutions that deliver safe, well-executed, and capital-efficient projects to clients across Canada and around the world. Working with our clients, we consistently deliver results with the safety and quality they expect.

© 2021 Fluor Corporation. All Rights Reserved. Fluor is a registered service mark of Fluor Corporation. ADCA211421

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13 CHOA JOURNAL — October 2021

The Last Barrel Standing: A Capital Markets Viewpoint on Canadian Oil Sands’ Sustainability Advantage BY JARED DZIUBA, CFA, BMO CAPITAL MARKETS OCTOBER 2021 CANADA’S OIL SANDS BUSINESS WILL BE A SURVIVOR.

Practicing ESG Since Before It was a Thing.

Within the context of an accelerating energy transition, our Capital Markets view is that Canada’s oil sands sector can position itself well for the future given:

Canada is regularly recognized as a leader in environmental, social and governance practices among the world’s largest oil reserve holders, according to independent evaluations including the Yale/Columbia Environmental Performance Index (EPI), Social Progress Imperative’s Social Progress Index, and World Bank’s Worldwide Governance Indicators. We highlight the sizeable gap in Governance quality between Canada and the rest of the oil-producing world as a critical distinction, as regulatory and corporate oversight is logically a root enabler of successful environmental and social stewardship.

its strong ESG leadership track record,

clear evolving technology pathways to net zero,

the inherently low decline, relatively low sustaining capital nature of extraction processes, and

unique existing and developing opportunities to divert bitumen from fuel end use, to non-combusted products.

If we are correct, the Canadian oil sands could stand as one of few oil sources outside of OPEC to sustain production, and potentially gain market share, in the global ‘friendly oil’ supply opportunity that we envision as inevitable for the coming decades. While this statement may conjure disbelief from some readers, let’s consider the elements that support the ‘staying power’ advantage of our oil sands.

Although contrary to the common narrative, these country ratings are reflective of Canada’s largest sectors, including oil and gas production. Indeed, Canada’s leading oil companies also achieve top ESG scores relative to global competitors according to consensus third-party ratings (CSRHub, Bloomberg SRI and MSCI), and these are consistent with our own internal Capital Markets assessment of the sector’s ESG trends.

“Canada is regularly recognized as a leader in environmental, social and governance practices among the world’s largest oil reserve holders.”

Exhibit 1: Canada #1 in ESG Categories vs Top Reserve Holders

Exhibit 2: Canadian Oil & Gas Companies Top Consensus ESG Ratings

Scrutiny Has Made Us … Better. We like to say that Canada’s energy companies have been “practicing ESG since before it was a thing.” The sector has historically faced years of intense scrutiny, some for good reason - early oil sands production practices were certainly novel and crude processes which logically raised concerns about negative environmental consequences. Since then, Industry’s business and operating practices have evolved considerably, including the emergence and dominance of less invasive in situ extraction methods such as SAGD. This same history of scrutiny has shaped the world-class regulatory system and corporate oversight that the oil sands industry has in place today, and our project operators have become more disciplined and taken further action than is typical for the rest of industry - from both operating performance and disclosure perspectives. The Results Are Evident. Our work shows that the oil sands sector has led the pace of improvement in numerous ESG trends over the past decade including progress in emissions intensity, freshwater use and tailings reductions, as well as social/governance progress such as Indigenous engagement, health and safety and ESG-linked compensation. Of headline importance, oil sands emissions intensity has decreased by 44% since 1995. More recently, reported intensity has fallen 27% since 2013 versus just 13% for global oil majors and 15% for legacy U.S. oil producers. Viewed another way, the average oil sands barrel has shaved off >22 kg/bbl versus just 5 kg/bbl for competing oils. As a result, we estimate the typical oil sands barrel now emits just 5% more than the global average crude over its full life cycle from

production to end use, while top-performing projects have belowaverage footprints. Oil sands producers have also reduced freshwater intensity by ~7%/ year since 2014 compared to just 3% for the global majors. Water recycling is the main differentiator, averaging 82% in 2019 versus just 29% for U.S. senior oil producers. In situ projects now routinely consume 60% less fresh water than conventional oil operations from hydraulic fracturing and waterfloods.

“Alberta’s bitumen holds a secret weapon in the transition ... the option to target ... several high growth ‘non combusted’ products.” Mining projects, which often represent the negative image of Canada’s oil sands in the media, have also greatly evolved in fluid tailings treatment and reclamation. Some projects have cut annual tailings volumes in half, and work is advancing on waterless extraction processes that could eliminate tailings while reducing water use and emissions.

Exhibit 3: Life Cycle GHG Emissions of Crude Oils (kg CO2e/bbl)

Exhibit 4: Oil Sands Water Recycling Comparison (% Total Water Use)

Exhibit 5: Leading Global per-Barrel R&D Investment ($million)

Industry-Government Collaboration Means the Best is Yet to Come. The sector’s environmental performance has been enabled by industry-leading technological and process innovation, and a uniquely high level of collaboration, including government funding sources. Oil sands producers have invested more than $11 billion in R&D over the past decade including a record $1.6 billion in 2019 – notably higher than the global majors on a per-barrel basis. We sense that mounting R&D was just starting to bear fruit prior to the pandemic, and a backlog of emerging innovation in the pipeline could be poised to drive future emissions even lower. The Last Barrel Standing. Oil producers almost everywhere are facing increasing pressure to drastically reduce emissions and define credible pathways to ‘net zero.’ Within this context, the average carbon intensity of Canadian oil sands brings the exposure of still being above the average of its competition. So, with Canada’s ESG leadership and R&D strengths in mind, where does the business go from here? In a recent indepth report titled “Survivor Canada: The Unparalleled Position of Canadian Oil in a Transition Challenge,” we outlined a detailed roadmap for how the Canadian oil industry may ultimately be a key survivor in an energy transition. First, there is a clear path to net zero stemming from ongoing R&D leadership and related emissions improvements, the concentrated nature of emissions sources being highly compatible with carbon capture, and transition investments.

“We sense that mounting R&D was just starting to bear fruit prior to the pandemic, and a backlog of emerging innovation in the pipeline could be poised to drive future emissions even lower.” Secondly, we emphasize that the inherent low decline, low sustaining capital advantages of the oil sands improve the sector’s staying power versus competing sources which face steep declines and reinvestment demands. Finally, Alberta’s bitumen holds a secret weapon in the transition away from fossil fuels – the option to target bitumen away from fuels toward several high growth ‘noncombusted’ products.

Pathways to Net Zero via Technology and CCUS. In an attempt to rationalize growing net zero commitments of producers, we can chart a hypothetical roadmap to this ambitious goal starting with planned and possible breakthrough technologies, large scale Carbon Capture, Use and/or Sequestration (CCUS) and investments in biofuels, hydrogen and renewables. Underlying this pathway, it is critical to understand that leading ESG performance is not just about fuzzy feelings – it is also having a measurable impact on the economic competitiveness of companies. The aforementioned ESG performance trends have all contributed to a 45% decrease in core oil sands operating costs since 2013. Oil sands projects also have among the lowest sustaining capital requirements globally at <$10 per barrel, pointing to cash costs <$40/bbl WTI to hold production flat. At the same time companies have adopted capital allocation strategies that emphasize discipline, cash flow harvesting and returns over production growth. These are crucial factors in both financial sustainability and future environmental progress. Assuming limited growth investment the sector could generate $260 billion in free cash flow by 2030 alone, supporting ongoing leadership in R&D and a faster pace of technological advancement versus competitors. We anticipate emissions intensity could improve another 20-30% by 2030 with planned innovations, with upside from breakthrough technologies under development.and a faster pace of technological advancement versus competitors. We anticipate emissions intensity could improve another 20-30% by 2030 with planned innovations, with upside from breakthrough technologies under development.

“Critically, oil sands processes are particularly well-suited to carbon capture given large, concentrated emissions point sources primarily from clean natural gas combustion.”

The “Alberta Advantage” in CCUS.

“... companies are making investments in complementary transition businesses including renewable power, biofuels and hydrogen to reduce onsite emissions or provide offsets.”

Despite technological advancement, aggregate oil sands emissions will remain significant, likely above 80 MT/year without more impactful breakthroughs, or carbon capture. Fortunately, Alberta has all the makings of a world leader in CCUS with abundant geological storage, extensive infrastructure and expertise, and a stringent regulatory system to oversee containment. Critically, oil sands processes are particularly well-suited to carbon capture given large, concentrated emissions point sources primarily from clean natural gas combustion. Assuming technologies eventually eliminate mobile and fugitive sources we expect more than 90% of oil sands process emissions may eventually be ‘capturable’ with next generation CCUS, given appropriate policy incentives. To date, lack of a comprehensive policy set has prevented widespread action; however, change may be in the wind with planned increases in the carbon price to $170/T by 2030, a ‘stackable’ clean fuel credit in 2022 and proposed federal CCUS tax credit. Complementary Investments Add, Not Subtract. As a final piece of the net zero puzzle, companies are making investments in complementary transition businesses including renewable power, biofuels and hydrogen to reduce onsite emissions or provide offsets. Suncor has led by example, with direct investments in wind and solar farms, as well as equity investments in biofuels and sustainable aviation fuel producers. We expect more to follow.

Inherent Sustainability Advantages.

The Road to Fossil-Free Transport is Paved with Asphalt.

There is also a vitally important fundamental differentiator supporting the longevity of oil sands supply: Oil sands extraction is a completely different process than conventional oil drilling and, as such, comes with several inherent sustainability advantages. Oil sands is essentially a ‘manufacturing’ process with very low declines and therefore low replacement risk and sustaining capital demands; conversely, major conventional production sources face very high declines, high replacement risks and cost over time. With sustaining capital needs of just <$5-10/bbl versus $20-25/bbl for conventional oil, Canadian oil sands companies have by far the lowest sustaining capital ratios in the business (sustaining capex over cash flow). This means that the oil sands can be viewed as one of the most economic sources of sustained long-term supply globally and should support its ‘staying power’ versus conventional oil sources which will face much more reinvestment pressure in a transition world. The cumulative land and water use implications are also significant: a modern SAGD project will disturb just one-fifth of the land and consume one-third the freshwater as a similar-scale tight oil project over its lifetime. We suspect land and water concerns will only increase.

Finally, oil sands bitumen contains an unusually high asphaltene content of 14-20% compared to 1-4% for most competing light oils. These ‘bottoms of the barrel’ give bitumen its relatively high production emissions profile, but ironically may also promote its use in several non-combusted products, for example, asphalt now and carbon fibre in the future – all markets that will see material growth on the back of population, mobility and infrastructure spending trends. Regardless of energy source, demand for road vehicles is widely expected to double by 2050 in support of massive infrastructure spending. As such, asphalt demand may grow by at least 3.6%/year to exceed 200 MT by 2030. Bitumen may also be well suited for producing carbon fibre if, as targeted, costs can be driven down to 1/10th those of current processes, while the U.S. Department of Energy has suggested a 50% reduction in cost could drive market expansion >10x. This little-known potential opportunity may play a vital role in the sector’s long-term sustainability as it suggests meaningful alternative markets may be available for bitumen in the event of long-term fossil fuel demand destruction. While still in its infancy, R&D is advancing rapidly and there are indications that non-combusted markets could potentially absorb >30% of bitumen supply, greatly reducing the downstream and end-use (Scope 3) emissions that comprise the largest portion of oil sands’ overall carbon footprint.

“This means that the oil sands can be viewed as one of the most economic sources of sustained long-term supply globally.”

Exhibit 6: Corporate Sustaining Capital Ratios (Sustaining Capital/Cash Flow)

Exhibit 7: Global Oil Supply Gap – Demand vs Decline (000 b/d)

Pivotal Moment to Capture Long-Term Opportunity. Our outlook for long-term global oil demand is more constructive than what is headlined in various hypothetical ‘net zero’ narratives. However, even in a transition where hydrocarbon-sourced fuel demand falls precipitously, we still see the need for substantial upstream investment to offset steep declines in global conventional oil production. It is logical to expect ESG friendly sources will play a meaningful role in such investments. If we are correct about the Canadian oil sands’ uniquely sustainable supply position, this sector could stand as one of few regions outside of OPEC to actually grow its market share over the next two decades. This is a pivotal moment, and an opportunity for the sector to double-down on its efforts and gain policy support for initiatives toward the mutual net zero goal. Government-industry cooperation and industry’s ambition have never been stronger, and we are increasingly optimistic that progress toward the sector’s goals will accelerate and maintain a leading pace. Our view: After all has been said and done, Canada’s oil sands industry will be a survivor. This article is based on excerpts from a larger report ‘Survivor Canada: The Unparalleled Position of Canadian Oil in a Transition Challenge’ published by BMO Capital Markets, June 2021. For a full copy of the report, please contact

“Government-industry cooperation and industry’s ambition have never been stronger, and we are increasingly optimistic that progress toward the sector’s goals will accelerate and maintain a leading pace.”

Jared Dziuba, CFA Director, Oil & Gas Equity Research, BMO Capital Markets Jared has extensive experience covering the Canadian large-cap, emerging oil sands and international energy sectors. In his current role as Oil & Gas Market Specialist, Jared oversees the evaluation and execution of industry thematic research and special projects. Recent studies include perspectives on the ESG performance of the Canadian oil sand sector, the opaque world of Natural Gas Liquids (NGL’s), Non-OPEC project supply and Electric Vehicles & Oil demand.

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Let’s build positive change together Our organization is passionately committed to the pursuit of a better world through positive change. We embrace your visions as our own and partner with you to develop better ideas that are smarter, more efficient, and innovative. Our global network of 9,000 professionals work on the world’s toughest challenges. Our experience spans over 150 countries around the world in the energy, metals, infrastructure, digital, and investments market sectors. As a proud Canadian company with our Global Oil & Gas Center of Excellence located in Alberta, we work closely with the communities in which we live and serve to ensure that our solutions optimize environmental protection, economic prosperity, social justice, and cultural vibrancy. Hatch’s presence in Alberta was established in 1998 and we have provided our services and expertise to numerous clients in oil and gas, government agencies, power utilities, industrial clients, and municipalities, within the mid-Canada region, as well as internationally. With offices in Calgary and Edmonton, we have extensive local experience in engineering design and construction management for the Upstream, Midstream, Downstream and LNG segments of the oil and gas industry. We are also focused on the energy transition, by helping our clients reduce their environmental impact. We do this through our expertise in decarbonization planning, hydrocarbon pipelines, waste-to-fuel and biofuels production, fuel handling, carbon capture utilization and storage (CCUS), hydrogen production and transport, and renewable power generation.

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22 CHOA JOURNAL — October 2021

As new technologies are developed, and societies begin to implement systematic change, the necessary energy transition is beginning to accelerate. We’re responding to this profound transformation by providing our clients with responsible energy solutions that will shape a new energy landscape, one that achieves a low carbon future for all.


The Net Zero emissions movement continues to gather momentum.

Solvents and Hydrogen

Pledges to achieve Net Zero have surpassed 70% of all global emissions, despite fossil fuels still supplying 84% of energy demand. The Canadian government has committed to achieving Net Zero by 2050, and five oil sands producers who represent 90% of total bitumen production have committed to the same.

Upstream oilsands emissions can be significantly reduced through solvents to replace aqueous extraction, both for In Situ and Mining. Piloting has been completed or is underway across a wide range of solvent types/concentrations/timing, as well as the addition or replacement by electromagnetic radiation. These technologies have other environmental benefits, including minimizing water usage and reducing land footprint. Steam additives represent a different mechanism but have potential to reduce steam/oil ratios by 5-20%.

THREAT OR OPPORTUNITY FOR THE HEAVY OIL AND OIL SANDS INDUSTRY? The Overall Trajectory is Clear … While it is fair to be skeptical of the speed and likelihood of achieving global or even national Net Zero, the overall trajectory is clear. The diminishing demand forecast for hydrocarbon-based transportation fuels, the global investments in hydrogen, the growing movement in circular plastics, and other global trends lead to a flattening and eventual decrease in global oil demand. Supply cost, carbon pricing, consumer behavior, and diversification will determine the suppliers who will prevail.

The potential for a hydrogen economy seems to be fashionable every 20 years, but this time there is sufficient capital, technology, and global government support that it appears likely to succeed at a material scale. Blue Hydrogen (Steam Methane Reforming plus CCS) represents a tremendous production opportunity for domestic use and exports; a node is in full development in the Greater Edmonton region, with many inter-related projects. Burning hydrogen in oil sands facilities, as a full or partial replacement to natural gas, could represent a significant opportunity to reduce emissions.

Achieving Net Zero, in any timeframe, will require significant outcomes in technology development and deployment. But the ramifications extend far beyond just technology – there are political, behavioral, market, and other influences and impacts to consider. Also, while the extraction and combustion of fossil fuels has garnered overwhelming attention, there are significant challenges relating to industrial, manufacturing, and building emissions that need to be addressed in parallel. However, this article will focus on challenges and opportunities in Canadian oil and gas.

“... there is no credible Net Zero scenario that doesn’t include CCS.” CCUS: A Potential Advantage for Alberta The most significant opportunity lies in carbon capture and storage (CCS); there is no credible Net Zero scenario that doesn’t include CCS. Alberta and Canada are fortunately very well positioned to deploy largescale CCS due to subsurface pore space, existing infrastructure, and local expertise. Key assets are already operational and can form the backbone of the opportunity – large-scale capture facilities at Quest and Boundary, transportation in the Alberta Carbon Trunk Line, CO2 injection at Clive and Weyburn, and R&D facilities at the Alberta Carbon Conversion Technology Centre and the Carbon Capture & Conversion Institute. These assets and operational expertise enable further expansion and position Canada as a global leader in CCS. Conversion and utilization will play a role, and could foster significant business opportunities, but large-scale storage will be crucial to achieving Net Zero.

WILL ONE OF YOUR IMAGES SPEAK A “KILOWORDS”? CHOA is asking you to submit your photos and graphics. We’ll work with you to publish submissions that can integrate well into our CHOA publications. We’ll acknowledge contributions we use. We’ll tell great stories together. Contact us now at OFFICE@CHOA.AB.CA


Bitumen Beyond Combustion Can Address Scope 3 Emissions

Converting Threat to Opportunity

Bitumen Beyond Combustion (BBC) products, like carbon fibre and asphalt binder, represent an opportunity to reduce “Scope 3” (end use) emissions by diverting 20-50% of hydrocarbon products to non-fuels within which carbon is sequestered. Moreover, the downstream impacts of BBC could further enable the shift to a Net Zero world, as these lowcost materials could enable fuel-efficient transport and longer-lasting infrastructure. Other BBC products include materials for energy storage (activated carbon, vanadium) as well as advanced carbon materials (graphene, nanotubes, carbides).

To invoke an overused cliché, the threat of Net Zero is actually an opportunity. With the right approach, Canada can leverage its existing assets and expertise to become a leader in enduring industries. Converting Net Zero ambitions from a potential threat to a real opportunity for the heavy oil and oil sands industry will require a level of innovation and collaboration not seen since AOSTRA, including parallel development of both technology and policy. How can we each do our part?

And More … There are a multitude of other technology opportunities that could play a role in achieving Net Zero – biofuels, geothermal, Small Modular Nuclear Reactors, Direct Air Capture, and a myriad of digital applications. Some are niche while others have broader potential, and some are close to commercial while others remain a “wildcard”. Bryan Helfenbaum, Executive Director of Advanced Hydrocarbons, Clean Resources division, Alberta Innovates Bryan Helfenbaum is the Executive Director of Advanced Hydrocarbons at Alberta Innovates, responsible for programs such as Recovery Technologies, Methane Emissions Reduction, Partial Upgrading, Digital Oilfield, and Bitumen Beyond Combustion. In addition, Bryan is a Theme Lead for the Clean Resource Innovation Network and a Fellow in the Energy Futures Lab. Prior to joining AI, he spent 20 years in a variety of technical, business, and innovation roles in industry. Bryan has a Bachelor’s degree in Environmental Engineering from Waterloo and an MBA from Calgary.

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INTRODUCTION The challenge of reducing Canada’s carbon emissions while simultaneously meeting projected growth in energy demand will require a fundamental shift in energy production. Nuclear and more specifically Small Modular Nuclear Reactors (SMNRs) are an attractive solution to help meet this future state (Canada Energy Regulator, 2020). Unlike wind and solar which suffer from intermittency concerns and the associated green-house gas (GHG) emissions associated with gas-fired generation, nuclear power can provide a steady baseload to the grid, is capable of load following improving overall grid stability and does not emit any GHGs (Office of Nuclear Energy, 2021). Unlike previous generations of nuclear power generation, the smaller footprint, scalable nature, and improved safety of SMNRs makes them attractive for niche energy markets, such as remote mines and communities, allowing for a much broader deployment than present, including implementation at oil sands mines and upgraders (Natural Resources Canada, 2021).

WHAT IS AN SMNR? SMNRs are essentially small versions of traditional nuclear facilities, physically requiring a smaller footprint and typically with a capacity no larger than 300 MWe per module (International Atomic Energy Agency, 2020). The modular nature of SMNRs means that components can be mass produced in factories and shipped to site for final assembly and installation, providing faster, cheaper, higher quality and more reliable construction than conventional nuclear facilities (International Atomic Energy Agency, 2020) (NuScale Power, 2021) (Natural Resources Canada, 2021).

Figure 1: Plot Plan of a NuScale SMNR Facility

The small size of each SMNR module allows for energy production to be tailored to the requirements of any given application – whether in single or multiple module configuration, SMNR plants can be scaled (to varying degrees) to meet energy needs and optimize operating costs, and in certain cases modules can be added incrementally to grow with demand (NuScale Power, 2021) (International Atomic Energy Agency, 2021) (Office of Nuclear Energy, 2021).

“SMNR plants can be scaled... to meet energy needs and optimize operating costs.” Canada’s SMNR Action Plan envisions the key markets for SMNRs being on-grid power, heavy industry, and power for remote communities (Natural Resources Canada, 2021). Other potential SMNR applications include process heat, power for water desalination and hydrogen production, and powering remote jobsites such as oil refineries and mines (World Nuclear News, 2019).

Figure 2: Three Streams for SMNR Development in Canada SMNR Action Plan



Nuclear power technologies are often categorized into “generations”, in which each generation represents a step change in reactor technology (World Nuclear Association, 2021). Generation I reactors are those developed in the 1950s and 1960s, all of which have been decommissioned as of 2015 (World Nuclear Association, 2021). Generation II reactors are those currently in operation across the globe (World Nuclear Association, 2021). Generation III reactors are considered “advanced” reactor technologies and are currently under construction or in the final stages of research and development (World Nuclear Association, 2021). Compared to Generation II, Generation III reactors have greater resilience against operational upsets, higher efficiency, longer operating life and less waste production (World Nuclear Association, 2021). Generation IV reactors are in early research and development or conceptual stages. Several SMNRs utilizing Generation III technology are anticipated to begin commercial operations in the late 2020s through mid-2030s (International Atomic Energy Agency, 2020). SMNRs utilizing Generation IV technologies are in development and will provide opportunities for higher temperature applications such as cogeneration and steam electrolysis when ready for commercial use, anticipated around 2040 (International Atomic Energy Agency, 2020).

Recognizing the opportunity for SMNRs in the Canadian market, the Canadian government launched Canada’s SMNR Action Plan in December 2020 (Natural Resources Canada, 2021). Developed in partnership with more than 100 organizations including municipalities, provincial governments, Indigenous communities, and industry leaders, the Action Plan establishes a set of plans and actions to realize the potential of SMNRs for Canada (Natural Resources Canada, 2021). Central to the Action Plan are three streams for SMNR development, intended to pave the way for bringing SMNRs online in Canada. These streams are: •

Stream 1: Construct the first grid-scale SMNR of approximately 300 MWe capacity at Ontario Power Generation’s Darlington Nuclear Generating Station site in Ontario by 2028, to be followed by units in Saskatchewan coming online starting in 2032 (Natural Resources Canada, 2021).

Stream 2: Deploy two advanced reactor designs at NB Power’s Point Lepreau Nuclear Generating Station, with demonstration units complete by 2035 (Natural Resources Canada, 2021).

Stream 3: Develop and construct new micro SMNRs intended to replace diesel generators in remote communities and mines, bringing a 5 MWe demonstration unit into service at Chalk River Laboratories in Ontario by 2026 (Natural Resources Canada, 2021).

SMNR TECHNOLOGIES There are over 70 different SMNR technologies in development globally, which fall into four main technology types: •


High temperature gas-cooled

Liquid metal-cooled fast neutron spectrum

Molten-salt cooled

All four designs contain the same key components: a nuclear core in which the nuclear reaction takes place, a cooling medium that transfers the radiated energy for steam production, a moderator to capture excess heat from the core and a heat exchanger that converts the nuclear energy into steam (which then is used directly in a process or turns a turbine for power production). Table 1 below provides a comparison of the key differences between the technologies. This article will focus on water-cooled and high temperature gascooled designs due to the utility in the oil sands market and design maturity (International Atomic Energy Agency, 2020), (Reyers, 2020). Water-cooled SMNR Technologies The water-cooled SMNR technology is the most like operating power and naval reactor designs today, and as a result has the lowest technological risk compared to the other SMNR designs (World Nuclear Association, 2021). Although light water reactor designs vary, this paper will depict a light water reactor design based on the NuScale technology. The core is situated at the bottom of the reactor (Figure 3) where water is heated as it passes over the core and into the steam generators. The reactor water (coolant) is used to heat a separate supply of water within tubes of the steam generator to generate steam. This steam can be used for power generation or thermal applications and the coolant returns to the core to repeat the process. Each reactor is placed within an Figure 3: NuScale Reactor Pressure Vessel







Light/Heavy Water


Various metals

Various Salts

Moderator Electrical Output (MWe) Core Outlet Temperature (oC)

Light/Heavy Water


Lead, Sodium or Helium

Graphite or Heavy Water

30 to 380

250 to 633

10 to 300

0.1 to 300

287 to 327

750 to 900

485 to 850

590 to 750

Table 1: SMNR Technologies Comparison (Source: International Atomic Energy Agency, 2020)

Figure 4: Example Water-Cooled SMNR Design underwater pool filled with cold water to moderate the temperature of the reactors as illustrated in Figure 4. (NuScale, 2021). High Temperature Gas-Cooled SMNR Design High Temperature Gas-Cooled (HTGC) SMNRs utilize a similar design philosophy as water-cooled SMNR designs, but due to the Tri-Structural Isotropic Particle Fuel (TRISO) coated fuel, helium coolant and graphite moderator, HTGCs can produce significantly higher temperatures (750-900ᵒC) than the water-cooled design (International Atomic Energy Agency, 2020) (Gen IV International Forum, 2020). Helium is heated as it passes over the TRISO coated particle core, cooling the reactant. The helium then passes through the steam generation unit, generating steam from the water within the steam generation tubes. This steam can be used for power generation or thermal applications and the cooled helium returns the core to repeat the process. The reactors are surrounded by graphite to moderate the reactor temperature (Gen IV International Forum, 2020). A figure of the HTGC design can be found in Figure 5.

Figure 5: HTGC SMNR Technology

SMNR DESIGN SAFETY SMNRs deploy several common passive safety features independent of the coolant technology, each technology type does have technology specific safety features which overarchingly result in SMNRs being significantly safer than historical designs. The extensive use of passive safety features in SMNRs promise to make these plants highly robust, protecting both the general public and the owner/investor. The result being that the Emergency Planning Zones (EPZs) which extend many kilometers around current operating power reactors are projected to be significantly reduced which has a significant impact on the infrastructure required to deploy an SMNR. SMNRs should allow nuclear power to be used confidently for a broader range of customers and applications than currently possible (

Some of the inherent safety features of SMNRs are as follows (World Nuclear Association): •

Small power and compact architecture and usually (at least for nuclear steam supply system and associated safety systems) employment of passive concepts. Therefore there is less reliance on active safety systems and additional pumps, as well as AC power for accident mitigation.

Lower power leading to reduction of the source term as well as smaller radioactive inventory in a reactor (smaller reactors).

Potential for sub-grade (underground or underwater) location of the reactor unit providing more protection from natural (e.g., seismic or tsunami according to the location) or man-made (e.g., aircraft impact) hazards.

Ability to remove reactor module or in-situ decommissioning at the end of the lifetime.

“SMNRs should allow nuclear power to be used confidently for a broader range of customers and applications than currently possible.” FUEL DISPOSAL The fuel disposal from water-cooled SMNR designs is very similar to those of water-cooled reactors. Typically, waste treatment and temporary storage facilities are provided on the reactor site but this varies between countries and fuel disposal waste programs (International Atomic Energy Agency, 2020). For example, for the SMART program in Saudi Arabia, the liquid waste is placed through a demineralization package to reduce the amount of volume of solid waste. The gaseous radiation waste system performs a holdup to allow radioactive gases to decay and then releases the gas in a controlled manner (International Atomic Energy Agency, 2020). Further research is currently underway for on-site lifetime storage of dry waste (International Atomic Energy Agency, 2020). HTGC technology is more advantageous in its fuel disposal due to its higher temperatures resulting in 40 percent less waste per unit of energy produced. As such, overall spent fuel storage and disposal can be 50 times lower (per volume) than water-cooled SMNR designs, significantly reducing the complexity and cost of the storage and disposal facility (International Atomic Energy Agency, 2020).

SMNR APPLICATION IN CANADA Estimates show that SMNR technology can supply 19,000 MW of Canada’s power generation by 2050 (EnviroEconomics; Navius Research). It is anticipated that SMNR power will have significant benefits in grid base power along with hydrogen production from electrolysis or steam methane (MIT, 2018). With the generation of hydrogen and steam, SMNR technology can also be utilized for oil sands in-situ extraction and upgrading. These SMNR technologies can be operated by any group with the adequate licensing and training, including oil sands producers.

“SMNR technology can supply 19,000 MW of Canada’s power generation by 2050.” Base-Grid Power Generation: By sending the steam produced in the steam generator to a steam turbine, SMNR technology generates power that can be delivered to the grid. With its modular design and grid inertia, SMNRs can be installed in remote parts of Alberta, away from existing infrastructure and fuel sources, enabling high quality power throughout Alberta and at remote worksites. Hydrogen Production: Hydrogen can be used to reduce carbon emissions in both the energy and transportation sectors; either as an energy storage medium or a fuel for hydrogen fuel-cell vehicles, trains, ships, and airplanes (Reyers, 2020). There are two main types of hydrogen production: green hydrogen through electrolysis from clean or renewable energy sources and grey hydrogen from steam methane reforming (blue hydrogen if it is in conjunction with carbon capture and storage) (Giovannini, 2021). Both water-cooled and HTGC SMNR technologies can be used for green hydrogen production. An oil sands producer would be able to supply enough hydrogen to their entire vehicle fleet with one SMNR. Because of the higher temperature, HTGC SMNRs can also be used for grey/blue hydrogen production (International Atomic Energy Agency, 2021).

“Hydrogen can be used to reduce carbon emissions in both the energy and transportation sectors.”

Figure 6: Anticipated Timeline for Commercial Operation of Select SMNR Technologies Oil Sands Facility: Utilization of steam and heating medium is vital in oil sands extraction and upgrading. It is possible to use both water-cooled and high temperature gas-cooled SMNR designs as both can achieve the high temperature steam requirements for in situ oil sands extraction (Reyers, 2020). High temperature gas-cooled SMNR designs, with their higher outlet temperature, can provide high temperatures for various processes within the upgrader along with in situ steam. With the additional ability to provide grey or blue hydrogen, the high temperature gas-cooling SMNR designs provide significant opportunities for an oil sands facility. With adequate standards and trained employees, oil sands operators could operate a SMNR technology at their oil sands mine / upgrader. Detailed evaluation of both the technology and licensor are required to ensure the specific vendor meets the technological application and government regulations.

DEPLOYMENT TIMELINE As of Q3 2021, China’s CNP-300 and Russia’s floating Akademik Lomonosov are the sole SMNR technologies currently in operation (World Nuclear News, 2019). Demonstration units for both China’s Linglong One SMNR and Russia’s BREST-OD-300 SMNR began

construction in Q2 2021 (China National Nuclear Corporation, 2021) (Rosatom, 2021). Further SMNR technologies currently in development are anticipated to begin commercial operation in the late 2020s to mid2030s, including NuScale, GE Hitachi and KAERI (International Atomic Energy Agency, 2020). Generation IV SMNR technologies, including those from TerraPower, ARC Nuclear Canada and Terrestrial Energy among others, will bring higher temperature production capabilities when available for commercial use in the mid-2030s to 2040s (International Atomic Energy Agency, 2020).

GLOSSARY OF TERMS & ACRONYMS CNSC: Canadian Nuclear Safety Commission HTGC: High Temperature Gas Cooled IAEA: International Atomic Energy Agency SMART: System-integrated Modular Advanced Reactor SMNR: Small Modular Nuclear Reactor TRISO: Tri-Structural Isotropic particle fuel

REFERENCES Comprehensive references for this article are located online.

Steven Brooks, PMP

Steven Brooks, PMP, is a project controls specialist at Fluor. He has a Bachelor of Science (Engineering Chemistry) from Queen’s University. Steven has over eight years of experience in project controls and project management, including debottlenecking of an oil sands refinery and construction of nuclear waste storage facilities. Steven has recently been engaged in the review and analysis of Canadian and Global SMNR applications and opportunities. Steven can be reached at Andrew Fraser, P. Eng Alberta

Andrew Fraser, P.Eng Alberta, is a process engineer at Fluor. He has a Bachelor of Chemical Engineering from Queen’s University and a Master of Chemical and Petroleum from the University of Calgary. During his time at Fluor, he has worked on a variety of projects in the Energy Sector; from site experience at a refinery, utilities at an oil sands upgrader, to designing a petrochemical facility. Most recently, Andrew has been actively reviewing Canadian and Global SMNR application as part of a study for a Canadian energy producer. Andrew can be reached at Fred Beranek, PhD Eng

Fred Beranek received his PhD in Nuclear Engineering in 1978 at the University of Wisconsin – Madison. Subsequently, he started his career that has now spanned over 43 years within the governmental nuclear industry, in the US, UK and Canada, primarily in the areas of Environmental, Safety, Health and Quality Assurance (ESH&QA), project management, engineering management, laboratory R&D, nuclear safety and management activities.

SUSTAINABILITY IS EMBEDDED IN THE WAY WE DO BUSINESS We are a resilient integrated energy leader with an unwavering focus on safety, asset integrity, and delivering leading and transparent environmental, social and governance performance. We are committed to our ambition to achieve net zero greenhouse gas emissions by 2050 and are taking bold action to address climate challenges through operational excellence, technology and innovation.


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SAGD Reservoir Characterization Considerations – Part 1 of 2 BY MARK SAVAGE, P.L.GEO.

INTRODUCTION The reservoir characterization process (the process) is the foundation for subsurface deliverables. The extent of the detail and focus areas required for the process are influenced by the overall project scope, schedule, and budget. The process should incorporate cross-functional (finance, facilities, etc.) and multidisciplinary (geoscience, reservoir engineering, etc.) input. This process has been used for a range of project decisions, up to significant decision gate (DG) milestones, DG1 (concept), DG3 (sanction), Figure 1, and resource and reserve determination and validation. By following this process, a thorough understanding of the steam-assisted gravity drainage (SAGD) asset potential and uncertainty can be gained. With some minor modifications, the workflow and considerations could be used across different asset types.

A vital component of the process is multidisciplinary collaboration. As a minimum, the following disciplines should be involved: geology, geophysics, petrophysics, geomodelling, and reservoir/production engineering. Depending on the project specifics, other cross-functional disciplines may be required: field operations, facilities, project engineering, drilling and completion engineering, risk analysis, and finance. There are three stages to the process workflow: data collection and geoscience analysis, petrophysical analysis and geomodel development, Figure 2. The 3-D geomodel and simulations are dynamic and may need updates from new learnings and information.

Each stage of this workflow will influence the degree of uncertainty captured in the performance predictions. These predictions are used to assess volumetrics, greenfield or brownfield optimal facility design capacity, number of wells required Figure 1: Simplified Decision Gate Example (Source: Savage, M., 2020) for a field or pad startup, and the schedule for production rate sustaining pads. The schedule should incorporate performance learnings and required modifications from the producing pads, e.g. updated 3-D geomodels, type curves, and simulations.

“A vital component of the process is multidisciplinary collaboration. ”

Figure 2: Reservoir Characterization Workflow (Source: Savage, M., 2020)

This commentary is part one of a two-part paper and addresses the data collection component of the process. Part two of the paper will address the petrophysical analysis and geomodelling components of the process.

Data Acquisition and Geoscience Analysis The purpose of completing the process is to evaluate and identify subsurface opportunities and risks. The acquisition of subsurface data is a fundamental component in the process. Collection of reservoir data relevant to the extraction technology used is critical. The process relies on data derived from multiple sources: openhole and cased hole logs, geological core description and analysis, outcrop data, lab tests and seismic (2-D, 3-D or 4-D). This data is used to quantify and qualify key micro, macro and mega-scale reservoir parameters, such as permeability, relative permeability, grain size, reservoir facies, bitumen geochemistry, geobody dimensions, clay mineralogy, porosity, and saturation. Interpretation of these data sets are required to capture the variance and uncertainty associated with reservoir heterogeneity. Openhole and Cased Hole Log Data All wells drilled to assess a reservoir should have openhole wireline logs run to measure critical in situ parameters (porosity and saturation), Figure 3. Depending on the basin’s exploration history, there may be different vintages and log data quality. Normalization of the log data in the petrophysical stage is critical. This data becomes input parameters for the 3-D geomodel, for the reservoir volumetrics and simulation. A few of the planned strat wells should be considered as observation well (Obs) candidates. Obs wells facilitate collection of real-time temperature and/or pressure data during the production phase, Figure 4. These Obs wells can also collect cased hole log data throughout the production life cycle. Obs well data can be used to calibrate both 4-D seismic and simulations, update resource and reserve estimates, and to revise the drilling, construction and the production schedules of the sustaining pads.

Figure 3: Openhole Wireline Logs with Core Information (Source: AER D54 2019 11387)

A cost-saving consideration for the openhole logging program is the addition of borehole image logs. This tool obtains in situ reservoir information while eliminating the cost to core wells beyond the Alberta Department of Energy Oil Sands Minimum Lease Evaluation continuation requirements. Borehole image log data should be calibrated by running the log in several cored wells. Technical justification for running borehole image logs is the capability to consistently assess reservoir facies, identify faults/ fractures and measure dip angle direction. This data, combined with bitumen geochemistry, can aid in analysis of potential reservoir baffles or barriers. The dip direction data can influence the optimal position and orientation of SAGD well placement. Ensure that the first producing pads have enough core and borehole image log data points to represent the critical reservoir facies. Add reservoir insight by targeting anomalous features on 3-D seismic with core or borehole image logs in planned strat wells.

Figure 4: Obs Well Temperature (red colour fill) and Pressure Data (blue colour fill) (Source: AER D54 2019 11387)

Figure 5: Obs Well Cased Hole Saturation Log and Temperature Data (Source: AER D54 2020 11888) Optimal data collection could include: •

Cased hole wireline saturation logs, baseline saturation survey is acquired before first steam;

Petrophysical comparison and calibration of the openhole and cased hole saturation data to identify variances: and

The first repeat log acquisition is typically 12 – 18 months after initial production and is influenced by Obs well distance from the SAGD well pair.

The steam chamber is defined by the convective heating zone, Figure 5. The conductive heating zone is defined by the warmed bitumen above the steam chamber. Production induced saturation changes, growth of the steam chamber, and the advancing “gas phase” are apparent with repeat acquisitions of the cased hole saturation logs. The saturation log data and learnings from repeat acquisitions can be used to calibrate 4-D seismic and modify future 3-D geomodels and simulations.

It is essential that the data from openhole and cased hole logs are normalized and calibrated. Interpretation of the log data should be vetted for consistency before using it in the 4-D seismic interpretations and generating updated 3-D geomodel realizations.

“A cost-saving consideration for the openhole logging program is the addition of borehole image logs”

Core and Outcrop Data A key piece of data is representative core from the reservoir and field, Figure 6. A crucial factor in the process is to ensure care is taken in cutting and transportation of the core to facilitate laboratory testing. The appropriate coring procedure should be determined by the multidisciplinary team and the service providers before finalizing the acquisition and testing program. There are two types of core analysis generally conducted: routine and special core analysis (SCAL). There are several routine core analyses (oil saturation, permeability, etc.) conducted to evaluate reservoir potential and risk. Essential core-derived data sets are Dean-Stark oil saturation, grain size, mud volume, porosity and permeability. Saturation and permeability are strong indicators of reservoir performance potential. The openhole wireline saturation data should be calibrated with the core derived saturation data. Another routine piece of data is the digital core photographs. These photographs, combined with the wireline logs and the core, are used to describe and interpret reservoir features, such as depositional environment, bedding, facies, fractures, faults and the

Figure 6: Oil Sands Core Photo Example (Source: AER D54 2019 8870)

“A crucial factor in the process is to ensure care is taken in cutting and transportation of the core to facilitate laboratory testing” degree of bioturbation. These features aid in quantifying the reservoir quality, risks and in the identification of geobodies. The geological reservoir facies typically used to describe SAGD reservoirs is a proxy for vertical permeability and is based on mud bed volume, not to be confused with interstitial clay content. Each SAGD operator has their own facies scheme, Figure 7, but the principle is the same, the lower the mud bed volume, the better the vertical permeability. A facies scheme is developed from the core, borehole image logs and the wireline logs. The SAGD process is heavily influenced by saturation and permeability, and most importantly, vertical permeability. Vertical permeability (Kv) is directly influenced by micro and macro-scale parameters: pore throat geometry, grain size distribution, clay type, bioturbation and the presence of mud beds. The horizontal continuity of mud beds is challenging to quantify (fluvial vs. estuarine vs. marine environments) and can be the most influential parameter on performance. Figure 7: SAGD Facies Scheme (Source: AER D54 2019 8668)

When conducting Kv SCAL tests, ensure that key reservoir facies are represented, including Inclined Heterolithic Stratification (IHS) units. The most effective Kv samples are taken from a full diameter core kept at ambient conditions (not frozen). Conducting Kv tests at operational conditions can provide additional information relevant to understanding ultimate recovery potential. This Kv data is fundamental to reservoir simulation. Two SCAL tests that are influential in reservoir simulation are relative permeability and pressure-volume-temperature (PVT) analysis. Reservoir engineering input is essential to discussions and decisions of relative permeability and PVT analysis, e.g., the number of samples per facies, sample location and test conditions (temperature, pressure, pore volumes, etc.).

potential impact on steam chamber development. This data may be integral to the 3-D geomodel and simulation outcomes. Lastly, a valuable part of the routine analysis is grain size analysis. Grain size analysis data is needed for consideration of sand control in the well design. Grain size distribution can be measured using one of two methods: sieve or laser analysis. Regardless, the method selected should be the same methodology used for future grain size analysis in the same pool. Readily available grain size samples can come from DeanStark retains. For SAGD projects, the basal 10 meters of pay need to be sampled, because this is where the production and injection well pair is positioned. Data that is sometimes overlooked is outcrop data analogous to the reservoir. Outcrop data may provide reservoir specific areal information

“Understanding clay mineralogy can assist quantifying the risk of reduced permeability from formation damage, induced by drilling fluid and/or injected fluids used for enhanced oil recovery.” Clay mineralogy can be valuable data. Specifically, the volume and location of swelling clays, in the context of the reservoir’s depositional environment. Understanding clay mineralogy can assist quantifying the risk of reduced permeability from formation damage, induced by drilling fluid and/or injected fluids used for enhanced oil recovery. A SCAL test of considerable value is bitumen geochemical analysis using core samples along the vertical profile of the reservoir. A bitumen geochemical profile can aid in identifying a baffle versus a barrier and

Figure 8: Steepbank McMurray Outcrop (Source: flickr Luck, R., June 2005)

that can be incorporated into geological interpretations and 3-D geomodels. Outcrop features such as continuity of mud beds, and lateral continuity of reservoir facies are key, Figure 8. This information may be used to assist in understanding and defining geologic baffles or barriers. It is critical that the data and interpretations from core analysis are checked and cleaned before use in the workflow. The statement “garbage in, garbage out” is true in this process.

Seismic Data Geophysics is essential to interpretation, evaluation, geomodeling and reservoir management. Seismic data is unique in the 3-D and 4-D perspective it provides, making it both a supplemental and complementary data source. The advantage of 3-D seismic is the vertical and areal coverage it provides across a pad or an entire development area. This scale of areal coverage is superior to other data sources and can identify reservoir features not encountered by the strat well program. Seismic is particularly useful in defining reservoir features with a distinct geophysical characteristic such as: •

continuity of mud dominant intervals;

potential thief zones (low-pressure gas);

mud-filled abandonment channels; and

other impediments to SAGD development.

Figure 9: 4-D Seismic Time-lapse Example (Source AER D54 2015 8870)

“The advantage of 3-D seismic is the vertical and areal coverage it provides across a pad or an entire development area. ” These geophysical learnings can be incorporated into a 3-D geomodel as either a hard surface or a soft trend, e.g. influencing geobody vertical or areal distribution. This will result in a 3-D geomodel that captures distinctive subsurface features that influence performance predictions and the range of uncertainty. Once the SAGD asset has been producing, 4-D seismic at selected periods over the asset’s life can provide further learnings into the steam chamber development. Adding periodic repeat surveys to seismic acquisition enables an ability to track, measure and monitor the steam chamber development over time, Figure 9. Note the increased conformance indicated by the reduction in gray coloured areas, from 2006 to 2012. This dynamic 4-D data can provide insight into the parameters used in facies definitions, and if a revision to facies scheme, 3-D geomodel and production simulation is warranted.

Conclusion Data collection directly impacts the quality of results in the reservoir characterization process. Spending adequate time to plan the data collection stage, and to facilitate contributions from multidisciplinary and cross-functional groups, including the service providers in the program design ensures an optimal reservoir characterization process. The integration of these different data sources will result in enhanced interpretations, in the generation of better geomodels and more representative production simulations. Part Two of this article will be published in the December 2021 issue of the Journal, including discussion of petrophysical analysis and geomodels.

Mark Savage, APEGA P.L.Geo.

Mark has been in the oil sands industry since 2000. Mark started his oil sands career with Petro-Canada working on the Lewis, MacKay River and Fort Hills projects. Since leaving Petro-Canada in 2008, he has been actively engaged in various in situ oil sands assets with Ivanhoe Energy Ltd., Statoil Canada Ltd. and Athabasca Oil Corporation. He has collaborated on and led in situ geoscience, operations and development teams.

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October 2021