CHOA 35th Anniversary Edition Journal - Issue 4

Page 1

April 2022

PATHWAYS

FORWARD

FORGING THE FUTURE CANADIAN FEDERAL AND PROVINCIAL CARBON CHARGES: WHICH PROGRAM IS RIGHT FOR YOUR COMPANY? THE CASE FOR LIQUID SOLVENTS: LESSONS LEARNT FROM INDUSTRIAL PILOTS ON STEAM-SOLVENT CO-INJECTION STRATEGIES TO FILL IN THE DETAILS FOR AN OIL SANDS RESERVOIR: KINOSIS EXAMPLE A SYSTEMATIC MULTIDISCIPLINARY APPROACH FOR OPTIMIZATION OF BROWNFIELD SAGD PROJECTS - PART 2 CARBON CAPTURE AND STORAGE: A CRITICAL PATHWAY TO NET-ZERO


THE MESSAGE FROM CHOA

EDI IN ACTION: MOVING BEYOND “THE FIRSTS” Many of us are talking about EDI – what does it mean, and how do we move beyond “the firsts”?

EQUITY. DIVERSITY. INCLUSION. EDI is a key CHOA theme. We partner with organizations such as Young Women in Energy (YWE) and DirectHer to amplify their efforts, and collaborate to move the needle.

WHAT DOES CHOA BOARD DIRECTOR CARRIE FANAI HAVE TO SAY ABOUT EDI? Being “the first” or “the only” is often hard. When you are the only woman, only genderdiverse person, or only visible minority at the table or on the shop floor, you stand out. As a young engineer I began my career like that, being the first woman, and I thought it was normal. I told myself I was up for the challenge and that I could handle anything. That was 1996. Although we’ve made important changes to

“Being ‘the first’ or ‘the only’ is often hard.” what is acceptable today in the working world, the numbers remain stagnant, as reported by Energy Minute, especially in the oil and gas industry, in STEM and in leadership. There are still too often “the first” or “the only” at the table; CHOA works to change that.

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PROUD OF CHOA’S DIVERSITY. I am proud to be a part of CHOA, with its diverse membership, volunteers, and board – the Board is 67% female, 33% visible minorities, and 8% Indigenous. It’s important for industry associations such as CHOA to exemplify EDI and demonstrate learning, sharing, and leadership “next practices” – which is what CHOA is all about. When we bring diverse perspectives and experience to the table, taking a “many voices” approach, we can solve complex problems such as energy transition in new ways, spark innovative thinking and create mutually beneficial outcomes.

“When we bring diverse perspectives ... we can solve complex problems in new ways.”

Another example: CHOA partnered with DirectHer and ATB Financial in 2021 to host a workshop and panel entitled “Board Basics”, for women, gender-diverse people, and their allies. The awareness created lessens barriers to boards becoming more gender diverse and inclusive. When we achieve diversity and inclusion on boards and ultimately within our organizations, those unique perspectives are translated into how the organization performs, driving the EDI changes needed to be representative of the communities we operate in. Join me, our Journal guest interviewees, YWE, and CHOA “to be the change we want to see in the world.”

“Join us, our guest interviewees, and YWE, ‘to be the change we want to see in the world.’”

MUCH MORE TO BE DONE. There’s so much more that every organization and individual allies can do to bring about more equitable, diverse and inclusive workforces. For example, I am grateful to my Grade 11 math teacher who encouraged me to go into engineering. His simple yet intentional action changed my professional trajectory, making me aware of a career path I knew nothing about. When the worth of diverse people is recognized and intentionally supported through professional development opportunities, that can lead to underrepresented groups being better positioned for advancement, being on boards and achieving leadership positions.

Carrie Fanai CHOA Director

CONNECT. SHARE. LEARN. LEAD.


THE JOURNAL OF THE CANADIAN HEAVY OIL ASSOCIATION OCTOBER 2021

April 2022

CHOA.AB.CA

Table of Contents 5

ENERGY MINUTE – WOMEN IN THE ENERGY SECTOR

7

HONOUREES ANNOUNCED FOR THE 2022 CALGARY INFLUENTIAL WOMEN IN BUSINESS AWARDS

9

CHANGING THE FACE OF ENERGY: ALBERTA’S ENERGY FUTURE IS PROMISING

13

Q&A WITH AWARD WINNER CHERYL SANDERCOCK

15

Q&A WITH AWARD WINNER LEORA HORNSTEIN

22

FORGING THE FUTURE

27

ENERGY MINUTE – THE CURRENT STATE OF TARGETS TOWARDS NET ZERO

29

CANADIAN FEDERAL AND PROVINCIAL CARBON CHARGES: WHICH PROGRAM IS RIGHT FOR YOUR COMPANY?

40

THE CASE FOR LIQUID SOLVENTS: LESSONS LEARNT FROM INDUSTRIAL PILOTS ON STEAM-SOLVENT CO-INJECTION

51

STRATEGIES TO FILL IN THE DETAILS FOR AN OIL SANDS RESERVOIR: KINOSIS EXAMPLE

62

A SYSTEMATIC MULTIDISCIPLINARY APPROACH FOR OPTIMIZATION OF BROWNFIELD SAGD PROJECTS - PART 2

71

CARBON CAPTURE AND STORAGE: A CRITICAL PATHWAY TO NET-ZERO

/CANADIAN-HEAVY-OIL-ASSOCIATION /CANADIANHEAVYOILASSOCIATION @CDN_CHOA +1 403 269 1755

The Canadian Heavy Oil Association extends deep thanks to the volunteers who have been creating this 35th Anniversary series of the CHOA Journal. The Journal’s Editorial Committee for formal technical articles comprises KC Yeung, Mark Savage, Catherine Laureshen, Subodh Gupta, Adrian Dodds, Eugene Dembicki, and Bruce Carey. The Layout Team comprises John Whitnack, Irina Reilander, and Darci-Jane McAulay. Caralyn Bennett, Gordon Holden, and Andreea Munteanu provide CHOA Board and Operations support.

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.

CHOA JOURNAL — April 2022 2


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EDI EQUITY. DIVERSITY. INCLUSION. A SPECIAL SECTION OF THE CHOA JOURNAL. Impartial voices. Distinct perspectives. Inclusive action. Celebrating achievement.

CONNECT. SHARE. LEARN. LEAD.

CHOA JOURNAL — April 2022 4


EDI

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CHOA JOURNAL — April 2022 6


Honourees Announced for the 2022 Calgary Influential Women in Business Awards

Third annual awards ceremony spotlights the caliber of Calgary’s leaders and recognizes the drive, success and business leadership of women in corporate Calgary. Axis Connects and its 2022 Awards Selection Committee are pleased to announce the honourees of the 2022 Calgary Influential Women in Business (CIWB) Awards. Shining a spotlight on influential business leaders in Calgary, these recipients will be recognized and celebrated at the CIWB Awards Gala on April 27, 2022 presented by National Bank Financial Inc. and TransAlta Corporation. “We cannot wait to celebrate six incredible leaders in our city at our in-person Awards Gala in April,” states Heather Culbert, Board Chair, Axis Connects and CIWB Awards. “The proceeds from the CIWB Awards fund Axis Connects, which is a non-for-profit committed to elevating women professionals into decision making roles. Numerous studies point to the kind of impact that professional development and informal networks have on the success of an individual’s career and the awards recognize and celebrate the individuals that are role models for, and champion these women.” Nominations from organizations and individuals across Calgary were submitted for consideration in six categories. Honourees were chosen based on their professional accomplishments, advocating for advancing women, influence, and business community involvement. Nominations were reviewed and selected by a committee of 30 esteemed business executives who are listed via: www.ciwbawards.com.

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“Numerous studies point to the kind of impact that professional development and informal networks have on the success of an individual’s career and the awards recognize and celebrate the individuals that are role models for, and champion these women.” Congratulations to the 2022 CIWB Award recipients: z

Lifetime Achievement presented by TD Bank Group: Dawn Farrell, Independent Director and Chancellor, Mount Royal University

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Large Enterprise presented by RBC: Jana Mosley, President, ENMAX Power

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Professional Services presented by Nutrien: Cheryl Sandercock, Managing Director and Co-Head Energy A&D Advisory, BMO Capital Markets

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Social Enterprise presented by PwC Canada: Kim Ruse, CEO, Calgary Women’s Emergency Shelter

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Small and Medium Enterprise presented by TC Energy: Eleanor Chiu, CFO, The Trico Group/ Trico Homes

z

Male Champion presented by CIBC: Jim Dewald, Dean and Professor, Haskayne School of Business at the University of Calgary

These inspirational business leaders will be recognized at an in-person event on Wednesday, April 27, 2022. This celebratory evening, led by representatives of the two Presenting Sponsors, National Bank of Canada and TransAlta, will recognize and celebrate these five outstanding female business leaders and one male champion. About Axis Connects Axis Connects is a non-profit in Calgary that was established to connect, collaborate, champion, and provide career development resources for women and diverse professionals in Calgary. Its mandate is to unite more than 115 organizations focused on women’s initiatives in Calgary. www. axisconnects.com About the Calgary Influential Women in Business (CIWB) Awards The Calgary Influential Women in Business (CIWB) Awards recognize the incredible business leaders advancing women and diverse professionals in Calgary. Honourees were chosen based on their professional accomplishments, advocating for advancing women, influence, and business community involvement.. The CIWB Awards recognizes five outstanding female business leaders and one male champion for women in Calgary and celebrates their accomplishments. www.ciwbawards.com.

LIKE THE JOURNAL? LIKE TO CREATE THE JOURNAL? Contact us if you’d like to volunteer to be part of • • • •

project managing graphics or layout writing/bringing in content marketing and advertising

Contact us now at OFFICE@CHOA.AB.CA

CONNECT. SHARE. LEARN. LEAD. CHOA JOURNAL — April 2022 8


Changing the Face of Energy: Alberta’s Energy Future is Promising

YWE is proud to recognize the 10 inspirational young women of 2021 who are leading Alberta’s energy transformation. Since 2014, YWE’s Awards Program has shone a spotlight on more than 70 women’s contributions to and accomplishments in Alberta’s energy industry. “The transforming energy sector promotes more women to lead, with their skill sets, their ideas, and their passion”, said Katie Smith-Parent, executive director, Young Women in Energy. “Alberta’s energy future will be diversified, sustainable and profitable, and these women are key in successfully seeing it through”. The 2021 YWE award winners are: z

Andrea Hepp, Deal Lead - Acquisitions, Divestments & New Business Development, Shell Canada Limited

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Bita Malekian, Engineer-in-Training, TC Energy & Founder of Water Movement

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Christina Iversen, Chief of Staff, Alberta Energy Regulator

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Ivy Cheung, Contract Performance Manager, Real Estate, Shell Canada Limited

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Janice Tran, CEO, Kanin Energy

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Joeti Lall, Senior Program Development Advisor, Enbridge Inc.

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Kristine O’Rielly, Senior Consultant, Delphi Group

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Lauretta Pearse, Civil & Environmental Engineer - Strategic Advisory Services, Associated Engineering

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Leora Hornstein, Well-Being Specialist, Cenovus Energy

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Vilasini P. Pillay, Director, Marketing and Social Impact, SkyFire Energy Inc.

The award winners are selected based on their commitment to challenging the status quo through new and innovative initiatives, demonstrative leadership (with or without the title), top performance, and their impact in the local community and larger industry.

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“Alberta’s energy future will be diversified, sustainable and profitable, and these women are key in successfully seeing it through.” A robust review process involving both a peer review and final executive evaluation by the 2021 YWE Awards Executive Selection Committee was completed over four weeks in January. Thank you to the 2021 Executive Selection Committee for lending their time and expertise: z

Dale Friesen, Senior Vice President, Corporate Affairs & Chief Government Affairs Officer, ATCO;

z

Geeta Sankappanavar, Founder & CEO, Akira Impact;

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Kent Ferguson, Co-Head, Global Energy, Global Investment Banking at RBC Capital Markets;

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Darlene Gates, Chief Operating Officer, MEG Energy;

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Jason Switzer, Vice President, Growth & Capital at Foresight Cleantech Accelerator Centre; and

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Alicia Dubois, Founder, Nish Synergies Advisory Group and former CEO, Alberta Indigenous Opportunities Corporation.

About YWE Young Women in Energy (YWE) believes young women have the power to change the energy industry for the better. Our mission is to increase the female voice, presence, development and leadership in Alberta’s energy industry. We serve our 4,500+ members through events and programs aimed to support them as they work tirelessly to improve the industry in their chosen professions. The annual YWE Awards program recognizes and rewards Alberta’s top young women who are ‘changing the face of energy’. www.youngwomeninenergy

3-MINUTE CHOA JOURNAL READER SURVEY: Tell us what you think about the recent issues of the CHOA Journal since October 2021: • • • •

What kinds of content do you enjoy most? What additional content would you like to see? What do you like least? What else would you like to tell us?

You can read recent Journals again at https://choa.ab.ca/choa-journal/ Send your thoughts to us now, at office@choa.ab.ca

CONNECT. SHARE. LEARN. LEAD. CHOA JOURNAL — April 2022 10


FUTURE INNOVATORS FORUM:

The Race to Net Zero

LEARN SHARE CONNECT INNOVATE DATE AND TIME

May 3, 2022 4:30 - 7:30 PM

LOCATION

Royal Glenora Club 11160 River Valley Rd NW Edmonton, AB T5J 2G7

INTERNATIONALLY ACCLAIMED KEYNOTE SPEAKER

Darcy Spady

Managing Partner Carbon Connect International

GET YOUR TICKETS HERE: https://choa.ab.ca/event/choa-future-innovators-forum/

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CHOA JOURNAL — April 2022 12


EDI

Q&A WITH AWARD WINNER CHERYL SANDERCOCK

CALGARY INFLUENTIAL WOMEN IN BUSINESS 2022 THE CIWB AWARDS Two years ago, Heather Culbert, Jenna Kaye, Marnie Smith and Katie Smith-Parent founded Axis Connects and the Calgary Influential Women in Business (CIWB) Awards to recognize and celebrate the amazing and talented women and male champions within the city of Calgary. The CIWB Awards champion the Calgarians who have achieved professional excellence while advancing women in Calgary. Funds from the CIWB Awards are used to develop a central collaboration and technology hub for women and diversity-focused organizations in Calgary to ensure these individuals are aware of the amazing resources available to them to support and advance their career development. Believe it or not, there are over 100 organizations working to advance women and diverse talent in Calgary that we can bring awareness to in a meaningful way. Our technology hub enables valuable connections and achieves the ultimate goal of empowering more women and diverse professionals in decision-making roles.

2022 CIWB AWARD WINNERS Following a robust nomination process, a 30-person Selection Committee comprised of leaders across various sectors in Calgary selected the 2022 winners announced on February 23. Each of the six professionals recognized through the awards supports female leadership across the city and demonstrates a passion for elevating those around them by broadening representation at the table. This year’s CIWB Lifetime Achievement Award honoree is Dawn Farrell, who recently retired as CEO and President of TransAlta Corp. The remaining recipients include Jana Mosley from ENMAX, Eleanor Chiu from Trico Homes and Kim Ruse from Calgary Women’s Emergency Shelter. The 2022 Male Champion honouree who advocates for the advancement of women is Jim Dewald, Dean of the Haskayne School of Business, University of Calgary.

Q&A WITH 2022 WINNER CHERYL SANDERCOCK Among the list of this year’s outstanding winners is Cheryl Sandercock, Managing Director and Co-Head of the Energy A&D Advisory at BMO Capital Markets. Cheryl is a professional engineer by trade and has demonstrated her commitment to elevating women in the typically male-dominated energy and financial services industries. Throughout her career at BMO Capital Markets, she has managed and promoted 15 professional technical women. Cheryl’s continued significant and enduring impact on Calgary’s business community and the energy industry, and society’s betterment through her professional, volunteer and philanthropic activities make her

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deserving of recognition at the Calgary Influential Women in Business Awards. We were happy to have a few moments to connect with Cheryl to get her perspectives related to women in leadership and the energy sector. Q: When it comes to women in leadership, specifically in the energy sector, what do you see as the most significant barriers to change? A: I think it’s deeply systemic rather than energy industry-specific. At the earliest level (kindergarten), messaging needs to include recognition that women are equally talented. Not just lip service, really meaning it, by listening to our language, not denigrating women unintentionally, especially at that early age. This article is too short for the long list of language atrocities we still tolerate - let’s stop. Also, we harm ourselves before anyone even enters the industry. The energy sector is much more progressive than people may think. So, our message to the community should be that our industry is an excellent place for people, including women. It has a critical role in the future of humanity. We’re up against the image of our industry as not being part of the future and, therefore, perhaps not the place to build a career – it affects all workers. Still, I believe it will disproportionately affect women’s choices and, hence, our talent pipeline.

“... our industry is an excellent place for people, including women. It has a critical role in the future of humanity.” Whether we want to change - we think we do - we need to commit to the next stage - including women, not just because we believe we are supposed to, but because we genuinely want to and think it’s beneficial. We value their contributions, and they know they are valued. This issue at hand is not energy industry-specific - it’s systemic. Similar to other minorities (while acknowledging that each is distinct and, of course, women of various minority groups have compounded challenges), we fight the inertia of everyone, preferring people who more closely resemble ourselves because it’s easier. It takes real work to overcome that.


Q: What has made a difference for you throughout your career? A: Being open to opportunities and having a very supportive network. Many of my business opportunities have come through my volunteer connections and vice versa, so the community involvement aspect has made a difference. In particular, it provided me with mentors and early leadership opportunities I may not have received otherwise. I feel incredibly fortunate to have had so many supportive people around me throughout my career – to all of them, thank you. Q: What steps would you recommend for companies aiming to increase the representation of women in leadership roles? A: The fundamentals are simple: hire them, promote them, and treat them well. However, “simple” and “easy” are not the same. Address every level in your organization and the students you hope to attract. It’s systemic - and there needs to be progress at every level to generate that cultural shift for it to become more natural.

“You may want diversity remember the “inclusion” - if you aren’t listening to them, why bother?”

Q: Why are you passionate about the energy sector? What about heavy oil and oil sands? A: Energy is so fundamental to quality of life and is a critical piece in our efforts to improve environmental stewardship. It has so many aspects to it – which is extremely interesting. The energy industry has numerous technical elements that are in continuous improvement - everything from drilling to transportation benefits from technological advancement in materials, fluid management, AI, machine learning, data analytics, etc.

“Energy is so fundamental to quality of life and is a critical piece in our efforts to improve environmental stewardship.” In Canada, the energy sector is the oil sands – gas and condensate demand are also tied to oil sands, and it’s improved our standard of living nationwide. We’ll continue to grow other pieces of our energy complex, such as renewables, and continue to enhance carbon release intensity in all areas of the industry to make the Canadian energy sector sustainable for a very long time.

Be relentless. If it was easy, we’d already be there. It’s a multi-year project, so don’t get discouraged. Critical mass is required (all levels), and that takes time - once you’ve got it, it becomes natural and easier to maintain. You may want diversity - remember the “inclusion” - if you aren’t listening to them, why bother? Make sure you know why you’re aiming for more women in leadership and that you believe in the answer. Otherwise, you won’t have the corporate stamina to keep up the necessary effort. Then it would be best if you were willing to hear the answer to why you don’t have them today and be ready to address that feedback. It’s not easy because most people don’t want to change, and they don’t prefer to work with those who look different than them. You have to believe in the value, and most don’t. If you do, it’s amazing who you’ll find if you go looking for her.

Cheryl Sandercock, Managing Director and Co-Head Energy A&D Advisory, BMO Capital Markets – Professional Services Award presented by Nutrien

Cheryl Sandercock is one of the industry’s most experienced and highly recognizable practitioners in the field of Canadian Energy Advisory services since 2003. She is a trusted advisor to clients completing over $75 billion of transactions in over 100 mandates for domestic and international public and private energy companies and state-owned enterprises. As a professional engineer (APEGA) she is active as a Responsible Member for the practice of the advisory services group which she leads, as well being active with her alma mater, the University of Calgary. She has a diverse set of professional industry memberships including the Petroleum Acquisition & Divestiture Association, Canadian Heavy Oil Association, Canadian Society for Unconventional Resources, Society of Petroleum Engineers, Energy Council and Women in Capital Markets. She is a regular industry guest speaker and panelist, as well as facilitating the participation of other industry colleagues to present and contribute to PADA, CHOA, SPE and CSUR.

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EDI

Q&A WITH AWARD WINNER LEORA HORNSTEIN YOUNG WOMEN IN ENERGY 2021 THE YWE AWARDS

Q: What are the realities of wellbeing in the energy sector?

Young Women in Energy (YWE) is an Albertan non-profit working to increase female voice, presence, development, and leadership in the Energy sector. One of their flagship programs is the YWE Awards, an annual awards program to recognize and celebrate ten (10) young women who are ‘changing the face of energy’ by both excelling in their chosen profession, while advancing their communities. YWE believes young women have the power to change the energy industry for the better. Since 2014, YWE has recognized more than 80+ Awards Alumni.

A: Energy sector workers face some unique, and some not-so-unique, challenges to mental health and well-being. Recent data indicates worse general mental health, more work-related stress, and higher incidents of diagnosed long-term health conditions than found in the general population. Our workers are challenged with relationship strain, loneliness and stress from being away from home. Additionally, camp living can come with poor morale, difficulty maintaining good eating, self-care and sleep habits. Stigma and in some cases, a lack of psychological safety remain a pervasive barrier to workers seeking and accessing support.

One of the 2021 YWE Award Winners is Leora Hornstein, Well-Being Specialist at Cenovus Energy, a CHOA Platinum Annual Sponsor company. Leora is a passionate advocate for both mental and physical ¬health at work. CHOA’s Andreea Munteanu sat down with Leora to discuss her passion for well-being and the future of Energy in Alberta.

Q&A WITH 2022 WINNER LEORA HORNSTEIN Q: Why are you passionate about the energy sector? A: Working in the energy sector means that every day, my work contributes to energizing the world. With the unique challenges our workers face such as shift and remote working, substantial physical and psychosocial risks, and a dynamic and rapidly evolving work environment, it means that I am always busy, challenged, and growing. This helps me to feel purposeful as I know that my work contributes to making peoples’ lives better every day.

“... I know that my work contributes to making peoples’ lives better every day.” Working in this sector means being a part of a welcoming community – a trip out to a worksite or camp makes evident the family-like feel that comes along with the many hours and days our workers spend together in close proximity, it’s something special to be a part of. Given the reach through the vast number of workers, working in this sector also means that the work goes beyond reaching individual workers and one company, it impacts and supports surrounding communities and the industry as a whole, as well our economy on a macro level.

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“... through small but steady and consistent actions, there is a significant opportunity to drive awareness, provide education and support to foster improved worker wellbeing ...” This said, the significant need to protect and improve mental health and well-being for the energy sector contributes to the criticality of this work and the industry is moving to address these challenges. The ability to reach a sizeable population of workers, many of them in a captive environment, means that through small but steady and consistent actions, there is a significant opportunity to drive awareness, provide education and support to foster improved worker well-being, a better work culture and organizational health. And ultimately, affect better business, innovation and people outcomes. These are exciting times – needs are high and organizations are starting to make the connection between worker well-being, productivity, engagement, physical and psychological safety and ESG commitments. ‘Fly-in, fly-out’ oilsands workers face significant mental health challenges, report suggests | Folio (ualberta.ca)


OPTIMAL OUTCOMES WILL BE REALIZED WHEN: z

a well-being strategy aligns and integrates into business priorities such as attraction, retention, performance, lower turnover, improved safety and greater creativity and innovation. Additionally, indirect priorities such as cost avoidance related to worker’s compensation and disability claim costs, benefit costs, reputational impacts and potentially legal costs.

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organizations understand improvements and change are incremental and not realized in the short term, return-on-value/ return-on-investment and realizing benefits take time

Q: What do you see as the wellbeing nexus that fosters optimal outcomes for companies and their employees?

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a holistic and full spectrum approach is taken – from prevention and protection, to intervention and access to support

A: For optimal outcomes, it is my belief that well-being needs to be integrated into a company’s fabric – it needs to be about how things are done, not a single line item on a performance plan. Ultimately, visible leadership support and commitment is critical and yet, well-being must be owned and driven through all levels within an organization. Managing workloads and encouraging opportunities for rest and recovery will support healthy ways of working. Having a business case that demonstrates the correlation between staff well-being and business results is necessary to support the resourcing and investment. Then there’s the paramount realization that supporting well-being is just the right thing to do – to protect the humans and lives that perform the work and are responsible for business results.

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a safe workplace is realized as business critical and extends beyond physical safety to include inclusion, diversity and psychological safety

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human connection is prioritized to include the social experience at work, and the whole life experience of each worker. Companies that foster connections amongst their workers, support workers’ ability to balance family commitments through benefits and flexibility, and support community giveback and partnership opportunities help to alleviate major sources of worker stress

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when data is used to understand needs, inform action and used over time to make improvements and measure return-oninvestment

“For optimal outcomes, ... well-being needs to be integrated into a company’s fabric – it needs to be about how things are done.”

With the shifting needs over the past two years, taking care of the people of a company with a human-first approach is central to success. Ultimately, companies that bring together healthy people, healthy work and a healthy culture will see a healthy organization and best outcomes.

“Authentically caring for people and having a humanfirst approach is pivotal to protecting, promoting and supporting well-being.”

Q: What simple actions can any organization take to improve wellbeing? A: Start somewhere and start now. Assess where the organization is currently at and where the greatest needs lie. z

What will matter most to your company? Set goals and objectives based on identified gaps which will help with program design.

z

Where should the focus be? There are many resources, vendors and experts in this field who can help and given that there is a cost involved, doing this the right way will help to bring both an ROI (return on investment) and a VOI (value on investment). There’s also a number of turnkey solutions, such as the Canadian Mental Health Association’s Not Myself Today program that make it easy for companies to implement a program quickly.

“Companies that bring together healthy people, healthy work and a healthy culture will see a healthy organization and best outcomes.”

z

What actions will yield the greatest impacts? Start by getting leaders onboard and driving employee participation and engagement through campaigns, ongoing communication, training and strategic program rollout. Find the champions, and use their passion and commitment to drive well-being broadly across the organization. Aligning well-recognized wellness days with internal campaigns, initiatives and communication is a useful way to demonstrate commitment and connect the dots, such as Canadian Mental Health Week in May. Specifically in the energy sector, connecting well-being to safety is a great way to start – broadening the topics of safety moments to include mental health and well-being topics is a useful way to bring awareness and start conversations. Assess and ensure basic benefits are in place for workers to access care and support. Authentically caring for people and having a human-first approach is pivotal to protecting, promoting and supporting well-being.

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Q: “What’s so great” about your YWE experience?

WELL-BEING PRACTICE/TRY IT OUT – CHECK-INS:

A: I’m incredibly honoured and grateful to receive this award, both on a personal level and a professional level. It’s a true testament to my personal commitment to this role and my personal value of living with purpose. It also highlights the importance and necessity of this work for the oil and gas industry. This affiliation with YWE will bring extra gravitas and exposure to the priority of supporting the mental health and wellbeing of our people, our organizations and our sector. I’m humbled to stand alongside a powerhouse of women – together we rise up to change the face of energy, enhance our organizations and communities, improve our industry and support our economy. I’m most looking forward to learning from and being mentored by other successful women who’ll foster my continued growth and development. YWE is a community of excellence, and I’m thankful to be a part of it.

Checking in with our own well-being each day is a great way to bring awareness to how you’re doing and what you’re feeling, and then use this information to guide the actions you may need to take to support yourself. This practice is also a good check-in opportunity to use within our teams, to get a sense of how others are doing and how best to support each other. Here’s a set of questions I think about each day, sometimes a few times a day as needed. These are based on my core values. Take a moment before you check in to ground yourself by finding a moment of stillness and become present with a few deep breaths to calm the mind.

“Together we rise up to change the face of energy, enhance our organizations and communities, improve our industry and support our economy” Well-being practice/Try it out – Reenergize yourself: The practice of energy management is important to prevent burnout and manage stress effectively. Being aware and bringing attention to balance your daily energy input and output is a critical practice to supporting your health and well-being. Working in the Energy sector we know that nothing runs on unlimited energy. I encourage you to think of daily selfcare practices as a means to replenish and energize yourself – physically and mentally.

“Consider two categories of reenergizing yourself: “doing more of” and “doing less of.” Consider two categories of reenergizing yourself: “doing more of” and “doing less of”.

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How am I feeling on a scale of 1-10 (1 = struggling, 10 = flourishing)?

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How can I be healthy and well today, physically and mentally?

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How can I help and feel purposeful today? (this helps me with my central value of living with purpose)

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Who do I need to connect with for support/guidance/ encouragement?

As noted, I’ve designed these to align with my core values – I encourage you to think about yours and what check-in questions will help guide you to living within and aligning with your values. Living this way will energize you, and bring an increased sense of satisfaction, happiness and purpose.

“Doing more of” are acts you to want to include to build your health, well-being and resilience. This includes fueling yourself with nourishing food and hydration, movement and exercise, healthy sleep hygiene and spending time connecting to others. Practicing gratitude and mindfulness, and embedding acts of kindness, compassion and giving will support a healthy mindset and help you live aligned to your values and purpose. “Doing less of” involves limiting or removing drains to your energy. Thinking about where you’re giving your energy away to protect it, knowing that it’s a finite source. Limiting media exposure including social media, worrying unnecessarily, unproductive decision-making, inefficient time management, self-criticism and lack of boundary setting can contribute to depleting your tank. The focus you give to managing your energy directly impacts those around you – your team, colleagues and family. Supporting your wellbeing means that you’ll be able to bring your best and most energized self, professionally and personally.

Leora Hornstein, Well-being Specialist at Cenovus Energy

Leora Hornstein is the Well-being Specialist at Cenovus Energy. Leora is a Registered Nurse, Certified Occupational Health Nurse, and a trained fitness and Yoga instructor. She is a healthy lifestyle enthusiast and feels a strong sense of honour in fulfilling her life’s purpose by doing work that serves others. Leora strives to protect and promote employee well-being to cultivate healthy workplaces, foster supportive work cultures and cultivate organizational health. Leora strongly believes that healthy, happy employees drive healthy, successful business results. Leora a 2021 Young Women in Energy Award Winner and received the CAPP (Canadian Association of Petroleum Producers) Industry Recognition Award in 2019 and 2020.

17 CHOA JOURNAL — April 2022


DirectHer is currently conducting an important research project with Mount Royal University to explore the experiences and barriers women and gender diverse people have in the board governance space (whether they are brand new or seasoned). To date, most research has only analyzed data about women who have achieved board positions with publicly-listed companies, but we think this leaves out a lot of important information that could be actioned into solutions across all board roles! We Need Your Voice! Participate in our survey: https://mtroyal.ca1.qualtrics.com/jfe/form/SV_dcfq7LbBjWw2Kqy The survey will take 15-30 minutes to complete. No previous board experience is required.


Together we raise the bar Innovation happens when people are brought together. Thanks, Canadian Heavy Oil Association for 35 years of helping members connect and accelerate their careers. Click here to learn about how we’re working together towards a better tomorrow.



Image courtesy of Athabasca Oil Corporation

INDUSTRY BRIEFS TECH FLASHES A NEW SECTION OF THE CHOA JOURNAL. Shorter, newsier content. Business and technical.

CONNECT. SHARE. LEARN. LEAD.

21 CHOA JOURNAL — April 2022


INDUSTRY BRIEF

FORGING THE FUTURE BY SHARON CROWTHER Indigenous businesses are thriving in the Athabasca oil sands and securing long-term prosperity for their communities. For Mikisew Cree First Nation, this means self-determination and the fulfillment of its slogan, ‘Pride of a Nation’. “I have worked in the oil sands for 35 years and, in that time, I have seen a huge shift in the role Indigenous business are playing in the industry,” says Mikisew Cree Chief Peter Powder. “Our businesses have grown from fulfilling janitorial roles to providing specialist engineering services, construction, mining, consulting, and more. And we’re very good at it,” he adds. “Where once Indigenous businesses were engaged to meet industry expectations, now their services are procured because they are indispensable, they are the best.”

“In 2021, Mikisew Group was recognized as one of Canada’s Best Managed Companies ...”

In fact, the value of procurement from Indigenous business in Northern Alberta’s oil sands is at an all-time high. In 2020, the combined Indigenous business spend of Suncor, Syncrude, Imperial Oil, Cenovus Energy and CNRL alone exceeded $2.5 billion. That’s a significant increase on the total industry spend reported for previous years, which, according to the Canadian Association of Petroleum Producers (CAPP), was $2.36 billion in 2019, $2.20 billion in 2018 and $1.54 billion in 2017. Procurement contracts encompass a range of services from maintenance to logistics and construction, all of which are provided by Mikisew Group, the business entity of the Mikisew Cree First Nation. The Group was founded in 1991 using a $26.2 million land claim settlement from the Government of Canada and in response to the decline of Mikisew’s traditional economy of commercial fishery and fur trade. Their founding mission statement included a plan to be self-sufficient through the development of revenue, skills and business by the year 2000. Today, they have a peak workforce of 750 staff employed through wholly owned businesses, a third of whom are Indigenous, working across more than 40 active long-term contracts through 12 different operating entities.

Chief Peter Powder, Mikisew Cree First Nation

“Indigenous businesses are thriving in the Athabasca oil sands and securing long-term prosperity for their communities. For Mikisew Cree First Nation, this means self-determination and the fulfillment of its slogan, ‘Pride of a Nation’.” CHOA JOURNAL — April 2022 22


In 2021, Mikisew Group was recognized as one of Canada’s Best Managed Companies and awarded the Aboriginal Economic Development Corporation Award from the Canadian Council for Aboriginal Business. The Group also surpassed $20 million in annual net economic benefit to Mikisew Cree First Nation through payroll, dividends and donations. These dollars directly impact the lives of Mikisew Cree members through education and training, healthcare and community services including youth programming and childcare.

Gallagher agrees that the shift in focus from procurement to partnership has been a positive one for First Nations communities. “Just like any other government, the Mikisew Cree First Nation has a budget and is always looking to improve the lives of its members by delivering services in the community,” he explains. “Through focusing on equity stakes in organizations, in addition to our wholly owned operations and various partnerships, we have been able to diversify and de-risk our business such that fluctuations in commodity markets are less impactful to our shareholder, the First Nation.”

“In 2021, Mikisew Group ... surpassed $20 million in annual net economic benefit to Mikisew Cree First Nation through payroll, dividends and donations.”

“When the Group started it was with the intention of creating jobs to offset those that were lost due to impacts on the Nation’s traditional ways of earning a living,” explains Dan Gallagher, Mikisew Group’s interim CEO. “And then, over time, our mandate shifted. As we expanded, we were able to offer roles in the heavy trades used on the oil sands sites as well as back-office functions such as HR, payroll and finance. Now we create careers for our members, not just jobs.”

“We have also grown by way of partnerships,” he continues. “At first it was just about our own businesses but now we look to partner with bestin-class operators that provide strategic services to our clients. These shifts have allowed us to provide reliable distributions leading to greater economic stability in the community.” Chief Peter Powder agrees. “We strive for self-sufficiency, and we understand that creating not just employment opportunities but also generating our own sources of revenue is paramount to seeing that goal become a reality,” he says. “As Canada’s first entrepreneurs, business is in our blood.” According to Ottawa-based think tank, the Macdonald-Laurier Institute (MLI), Indigenous communities involved in the resource sector have been gaining significantly more influence over the past 20 years, driving a shift towards project ownership. “The trend in recent years has evolved towards Nations asserting themselves as partners, owners and shareholders in resource development,” wrote MLI fellow Heather Exner-Pirot in a May 2021 report. “This is often the most consequential way through which they can achieve economic self-determination and real leverage in how projects proceed,” Exner-Pirot continues.

Gallagher believes the epitome of this model is the 2017 East Tank Farm deal, whereby Mikisew Cree First Nation and Fort McKay First Nation made history when they acquired a 49 per cent share of Suncor’s East Tank Farm Development, a bitumen and diluent facility north of Fort McKay.

At the time, the $503 million deal was the largest business investment to date by a First Nation entity in Canada and provided an important economic model for Indigenous communities across the country. Revenue generated by the facility has already paid for essential housing, to alleviate a long-term housing crisis within the community, and will be a major contributor to the Nation’s operating budget for generations to come. “The East Tank Farm deal came about after years of dialogue and collaboration between Suncor and the Nation’s Government and Industry Relations teams, who were looking to take our community benefit agreement to a new level,” recalls Gallagher. “The cornerstone of the deal was a true understanding by Suncor that an equity stake in the tank farm would deliver benefits far beyond what traditional contracting opportunities had been providing,” he says. “They pioneered a shift in the marketplace and demonstrated that there is a better way to deliver on community agreements by partnering with the Nation to ensure longterm economic benefits. This breakthrough partnership has shifted the way our clients think about how they can engage at a deeper level with the Economic Development companies from each of the various Nations in the region.”

“The trend in recent years has evolved towards Nations asserting themselves as partners, owners and shareholders in resource development ... This is often the most consequential way through which they can achieve economic self-determination and real leverage in how projects proceed ...” 23 CHOA JOURNAL — April 2022


“The East Tank Farm partnership signalled a shift ... to a new type of engagement ... one that allows direct participation for Indigenous communities in energy development ...” “The East Tank Farm partnership signalled a shift in how Suncor and Indigenous communities can work together. It demonstrated our commitment to a new type of engagement—one focused on reconciliation as part of our long-term sustainability goal and one that allows direct participation for Indigenous communities in energy development,” adds Curtis Serra, Suncor’s General Manager Commercial. “The agreement will provide a steady stream of revenue to both Mikisew Cree First Nation and Fort McKay First Nation for at least 25 years.” But the major legacy of the East Tank Farm Development lies in the discussions it ignited among First Nations leaders across Canada and the deals which have been inked since, including a $1.5 billion deal between Suncor and eight Indigenous communities to purchase part of the Northern Courier Pipeline and a partnership agreement for the Cedar LNG project, the first majority Indigenous-owned LNG export facility in Canada. “Demonstrating successful business partnerships to other First Nations, and learning from their successes, has created a period of rapid growth for Indigenous businesses in the oil sands sector,” reflects Chief Peter Powder. “We know that successful Indigenous businesses inspire other Indigenous business owners and entrepreneurs,” he says. “They also hire more Indigenous people who then gain the experience to fill more senior management roles within the sector, and so on. The rate of growth and expansion of Indigenous businesses in the oil sands should be expected to accelerate rapidly in the coming years, which is an exciting prospect for the First Nations communities Mike Heck (Suncor), Chief Peter Powder (MCFN), Dan Gallagher (Mikisew Group, CEO) (left to which will benefit.” right). “Thebacha” refers to partnership of Suncor and the Mikisew Cree First Nation. In 2017, the Mikisew Cree and Fort McKay First Nations joined forces to buy 49% of Suncor’s East Tank Farm development, resulting in the largest and most significant business transaction in Aboriginal history to that date.

“... the major legacy of the East Tank Farm Development lies in the discussions it ignited among First Nations leaders across Canada and the deals which have been inked since ...” Sharon Crowther

Sharon Crowther is an Alberta-based freelance writer whose work is regularly published in the Globe and Mail, Calgary Herald, BBC Online and publications around the world. She writes on a wide range of topics from business and technology to real estate, sport, travel and the arts. She enjoys discovering new narratives in old stories and was excited to learn that Indigenous leaders and Northern Alberta’s oil sands industry are finding new ways to partner and build long-term wealth for Indigenous communities.

CHOA JOURNAL — April 2022 24


The Canadian Heavy Oil Association (CHOA) and the Society of Petroleum Engineers (SPE) Calgary Chapter are pleased to announce their collaboration in cross-promoting select events to benefit the members of both associations. We know we are … stronger, together. This CHOA - SPE partnership will promote innovation, building and sharing knowledge to ignite and drive advances, and cross-industry collaboration to inspire our current and future leaders. With the combination of CHOA’s heavy oil and oil sands focus and SPE’s breadth including its data science Special Interest Group, members of our industry and beyond will have access to an enhanced range of events, information, and networking. Result: More opportunities to evolve and thrive in our continuously changing business environment. Join us. www.choa.ab.ca www.specalgary.com 25 CHOA JOURNAL — April 2022


How the World Mismanaged the Energy Transition May 4 - 12:00 PM MST The Calgary Petroleum Club

REGISTER HERE

Managing Reservoir Depletion and Parent-Child Well Communication May 4 - 12:00 PM MST The Calgary Petroleum Club

REGISTER HERE CHOA JOURNAL — April 2022 26


INDUSTRY BRIEFS

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CHOA JOURNAL — April 2022 28


INDUSTRY BRIEF

CANADIAN FEDERAL AND PROVINCIAL CARBON CHARGES: Which Program is Right for Your Company? BY PETER BRYSON

TODAY’S CARBON EMISSIONS LANDSCAPE IN ALBERTA AND SASKATCHEWAN With the ongoing changes to federal and provincial carbon fee programs, the Canadian oil and gas sector has seen many businesses struggling to understand what is needed and expected of them. The goal with this article is to help you understand the impact to your business as we explore the changes that the Federal Greenhouse Gas Pollution Pricing Act (GGPPA), Federal Fuel Charge (FFC), and the provincial programs put in place. The provincial programs are Alberta’s Technology Innovation and Emissions Reduction (TIER) Regulation, and Saskatchewan’s Management and Reduction of Greenhouse Gases (MRGHG) Regulation. One aspect of these carbon regulation changes is that, historically, fuel and flare, consumptions were considered “losses” in the oil and gas industry, one result of which is they were typically not subject to royalty charges or emissions-related levies. In 2019 the Government of Canada imposed a Federal Fuel Charge (FFC) across the country that applied unless a provincial carbon tax or charge was in place. Notably, the FFC applies to fuel and flare gas volumes.

“Historically, fuel and flare consumptions were considered “losses” in the oil and gas industry, one result of which is they were typically not subject to royalty charges or emissions-related levies. In 2019 the Government of Canada imposed a Federal Fuel Charge (FFC) that ... applies to fuel and flare gas volumes.”

29 CHOA JOURNAL — April 2022

At the time, the Alberta Government had exempted industrial users from this tax until 2023. With the rescinding of the Alberta carbon tax in 2019 these exemptions went away, leading the Federal Government to announce that Alberta would then be included in the FFC starting in 2020. Saskatchewan did not have a provincial carbon tax at the time, so it was subject to the Federal Fuel Charge starting from its inception in 2019. The FFC has been charged at $20 per tonne of carbon dioxide equivalent (TCO2e) starting in 2019 and has increased $10 per TCO2e per year until 2022. It will then increase by $15 per TCO2e per year with a cap at $170 per TCO2e in 2030. The federal tax applies to 21 products, including propane, ethane, marketable natural gas (which is considered anything that is a consumable product), and non-marketable natural gas. As mentioned earlier, the FFC applies to fuel (e.g., for gas-fuelled drivers) and flare volumes that historically have been considered losses and, as a result, have not attracted costs. The Alberta TIER Aggregate Program In January 2020, Alberta replaced the existing Carbon Competitiveness Incentive (CCIR) Regulation with the revised, renamed TIER program, which was modified to adapt an aggregate program. The TIER program, which is operated by Alberta Environment & Parks, is available to large emitters (cement plants, oil sands), opt-ins (power plants, companies with large gas plants), or aggregates. Each of these levels of the TIER program has different commitments to reduce emissions on an ongoing basis. The aggregate program, which is the focus of this article, allows any facility with less than 10,000 TCO2e emitted annually to join the program as an aggregate. An aggregate means two or more facilities. A company’s facilities are combined into one filing and could potentially become exempt from the Federal Fuel Charge. We will focus mainly on the aggregate program through this article. While we are focusing on the Alberta program the Saskatchewan program is very similar in nature.

“... an organization is not exempt from the federal program until it receives the final approval from the CRA”


The process to opt into the provincial programs for aggregates, and hence become exempt from the federal fuel charge, is quite specific and detailed. z

The first step is to fill in the appropriate aggregate application and submit to the appropriate provincial body.

z

Once approved by the provincial body, the approval is sent to Environment and Climate Change Canada (ECCC).

z

Upon approval from ECCC, the last step is to register as a distributor and emitter with the FFC administrators, Canada Revenue Agency (CRA).

z

Once the CRA registration is obtained, an emitter can then classify itself as exempt from the FFC and is under the obligations of the provincial program.

An important thing to note is that an organization is not exempt from the federal program until it receives the final approval from the CRA and, if an organization is not accepted into the TIER program at any step in the process, it must continue to participate in the FFC program. Once accepted into the TIER program as an aggregate, a company must make a commitment to reduce its emissions intensity by 10% per year or be subject to a compliance fee which is based on the FFC. In simple terms emission intensity is fuel divided by production. It is estimated that aggregators within a provincial program will see significant savings once enrolled and acknowledged. The cost, however, of administration of the provincial programs is approximately $15,000 to $20,000 annually. Therefore, a comparison of a company’s FFC vs. the cost of administration is important. Ascertaining correctly which program to be in at any point in time can mean significant cost savings to a company.

Natural Gas Fuel and Flare Attract High Costs Under FFC A high-level calculation is that marketable natural gas fuel or flare consumed in an operation subject to FFC will cost the operation approximately $98/e3m3 in 2022, escalating to $324/e3m3 in 2030 (nonmarketable natural gas is around 30% higher)

“A high-level calculation is that marketable natural gas fuel or flare consumed in an operation subject to FFC will cost the operation approximately $98/e3m3 in 2022, escalating to $324/ e3m3 in 2030 ...” In Figure 1.1, above, orange bars represent the charge per e3m3 of fuel or flare consumed, at the federal level (FFC) for Marketable Natural Gas and blue bars represent the cost per TCO2e as prescribed for Marketable Natural Gas under the Canadian Federal Government FFC.

Figure 1.1: FFC Charges per TCO2e and per e3m3 of consumption

CHOA JOURNAL — April 2022 30


Operators Could Benefit Substantially from Registering in a Provincial Program In 2022, a typical $20,000 TIER annual administrative cost would take approximately 20 e3m3 of natural gas fuel consumption per month to cover the costs of the FFC. By 2030, this breakeven volume goes down to 5 e3m3 of fuel per month. In high-level studies we have completed, based on the month of February 2022 there are approximately 450 operators across Alberta and Saskatchewan that reported fuel consumption. About 100 of those likely would not benefit from being in a provincial program. By 2030, this number will be cut in half. These numbers do not include the FFC cost of flare, which further incentivizes moving to a provincial program.

There are a few key differences between the FFC and the provincial carbon tax programs. For example, currently in 2022, the provincial carbon taxes only apply on the fuel emissions, and the flare and vent emissions are exempt (although it is believed that this may be changing in the future), and the federal tax is applicable to both fuel and flare emissions. Also, the provincial carbon tax is an annual remittance (with the obligations being due and payable on June 30 of each year), versus the federal, which is monthly.

“... there are approximately 450 operators across Alberta and Saskatchewan that reported fuel consumption. About 100 of those likely would not benefit from being in a provincial program. By 2030, this number will be cut in half.”

While the required 10% reduction in annual emissions for aggregate facilities may seem daunting, the reality is that companies need to work towards reducing their emissions intensity to help industry, Alberta and Canada reduce their overall carbon emission targets – and there are substantial financial incentives to do so. There are multiple ways to achieve such a reduction while running a business efficiently. An example would be adding new production with lower fuel intensity in its production and processing, or programs to reduce fuel consumption via electrification or installation of solar / wind power.

Although there are some big differences between these two types of programs, one thing that has changed for the better is that neither the federal nor provincial programs are technically considered a tax. Therefore, the charge and any fees associated are chargeable to the operating joint account and are potentially deductible for income tax purposes.

One thing to note, no matter what program the company plans on enrolling in, is that in 2020, provincially, there were changes to fuel, flare, and vent reporting. Prior to 2020, these three classifications were reported in one category called “fuel”. With the changes to the provincial reporting in January of that year, they were now required to be reported separately, in the three separate categories. Although this increases reporting work, it gives companies an opportunity to mathematically decrease their emissions by properly separating the losses into either fuel, flare, or vent.

Figure 1.2: Estimated Annual Cost Differences between Federal Fuel Charge Program and a Provincial Program for 1000 e3m3 per Year

31 CHOA JOURNAL — April 2022


A review of the volumes for the month of February 2022 was conducted on facilities that are marked as bitumen or heavy oil facilities for both Alberta and Saskatchewan producers. Based on companies that would be eligible for the aggregate programs, it was determined that the average of all those companies fuel was approximately 980 e3m3 per year, or 80 e3m3 per month.

Operators Could Benefit Substantially from Registering in a Provincial Program

Based on that information, we used a volume of 1000 e3m3 annually on Marketable Natural Gas to project the FFC vs. provincial program costs, excluding administration, with the assumption that the ratios of fuel to production remain unchanged. We also assumed that the provincial programs will remain unchanged for the period to 2030. We know that there are ongoing discussions and modifications to the programs that will change these numbers on an ongoing basis.

The path forward for most companies is highly reliant on diligence. The recommended steps are:

In Figure 1.2, below, the red line represents calculated costs for a company in the FFC program, and the orange line represents what the same company would pay if enrolled in its provincial program, assuming its emissions intensity stayed relative to their benchmark. Clearly, ascertaining correctly which program a company should be in at any point in time can mean significant cost savings to that company.

“The costs associated with Canadian federal and provincial carbon levies are becoming an increasingly important factor in overall operating costs for emitters.”

In 2022, a typical $20,000 TIER annual administrative cost would take approximately 20 e3m3 of natural gas fuel consumption per month to cover the costs of the FFC. By 2030, this breakeven volume goes down to 5 e3m3 of fuel per month.

1.

Ensure that fuel, flare and vent gas volumes are recorded and reported correctly.

2.

Ensure that meters are calibrated and working correctly.

3.

Have an accurate and complete equipment inventory.

4.

Consider a commercially available emissions management program to assist in correctly recording and reporting your emission volumes.

5.

Inform program managers of any changes to equipment usage and agreements.

6.

Provide training for asset and development groups, accountants, and emissions teams. All teams need to be aware of where the emission reductions can best be implemented and utilized going forward.

7.

Assess whether to opt-in to a provincial program.

8.

Review all applicable government programs for funding in reducing emissions and register with the necessary government agencies.

9.

Review all operations monthly, to ensure that forms and submissions are up to date.

10. Monitor Federal and Provincial programs for changes as there are new developments occurring at a rapid pace. The costs associated with Canadian federal and provincial carbon levies are becoming an increasingly important factor in overall operating costs for emitters. Careful assessment of reporting methods, carbon levy program choices, and physical emission intensity reductions is now a key business imperative for oil and gas operators.

Peter Bryson, President of TriAcc Group Inc.

Peter Bryson is President of TriAcc Group Inc. and has been in the oil and gas industry in various roles over the last four decades. TriAcc Group Inc. is a boutique consulting firm specializing in back-office administrative support to the Oil and Gas industry. Peter can be reached at peter.bryson@triacc.ca if you have any questions regarding this article.

CHOA JOURNAL — April 2022 32


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OPINION A NEW SECTION OF THE CHOA JOURNAL. We won’t always agree. But there can be value in putting it out there anyway. For discussion. Differences. Debate. What do you think?

CONNECT. SHARE. LEARN. LEAD.

39 CHOA JOURNAL — April 2022


OPINION

The Case for Liquid Solvents: Lessons Learnt from Industrial Pilots on Steam-Solvent Co-injection

BY ZHANGXING (JOHN) CHEN, RAN LI, WEI WU, SHENG YANG, JINZE XU, QIONG WANG, MOHSEN KESHAVARZ, XIAOHU DONG, XINFENG JIA, MIN YANG, MAOJIE CHAI, AND DONGQI JI* RESERVOIR SIMULATION GROUP, DEPARTMENT OF CHEMICAL AND PETROLEUM ENGINEERING, UNIVERSITY OF CALGARY (*CURRENTLY: M. KESHAVARZ AT SUNCOR ENERGY INC., X. DONG AND X. JIA AT CHINA UNIVERSITY OF PETROLEUM (BEIJING), M. YANG AT CHINA UNIVERSITY OF PETROLEUM (QINGDAO), AND D. JI AT CHINA UNIVERSITY OF GEOSCIENCES (BEIJING)) ABSTRACT Adding a solvent in a steam-based recovery process is conducive to mobilizing bitumen through solvent dissolution, reducing water usage by decreasing steam consumption, decreasing greenhouse gas (GHG) emissions released by the recovery process, and potentially unlocking currently uneconomical reservoirs. This article stems from a presentation at the annual Energi Simulation Summit in 2021, summarizes the lessons learnt from several key pilot evaluations, and will shed light on finely designing viable solvent-steam co-injection strategies and projects.

ABSTRACT Steam assisted gravity drainage (SAGD) has proven to be the most promising process for the commercial in situ recovery of bitumen in Alberta [1]. For high quality and thick reservoirs, SAGD can achieve a bitumen recovery of over 50% original bitumen in place (OBIP) and a steam-oil ratio (SOR) of 2.5 to 4.0. But for thin (thickness less than 15 m) or partially depleted or low bitumen saturation reservoirs, the SOR can be much higher, and the process becomes uneconomic due to an excessive heat loss to the overburden and a large heat requirement to heat the reservoir rock. Oil production companies have continued to look for alternative processes for more economic and more environmentally sustainable recovery of bitumen, particularly when the Canadian government has announced plans [2] to increase the carbon tax from its current level of $30 per ton to $170 per ton over the next nine years in responding to climate change. The most recently issued data from the Government of Canada indicated that in situ thermal operations in Alberta emitted 43 megatons (Mt) of carbon dioxide in 2019 [3]. Promising avenues for improving SAGD to achieve lower costs and lower carbon emissions include steam-solvent co-injection recovery processes. Examples include the Solvent Aided Process (SAP), Liquid Addition to Steam for Enhancing Recovery (LASER), Expanding Solvent SAGD (ES-SAGD), Solvent Assisted SAGD (SA-SAGD), Solvent Cyclic SAGD (SC-SAGD), Solvent Co-Injection (SCI), Solvent Low Pressure SAGD (SLPSAGD), and Enhanced Modified Vapour Extraction (eMVAPEX) processes [4-13]. Adding a solvent is conducive to diluting bitumen and reducing its viscosity through solvent dissolution whose effect is determined by solvent mass transfer and heat conduction in the reservoir. A large solvent diffusion coefficient leads to a high oil mobility and consequently

an uplift in the bitumen production rate. In addition, solvent injection reduces freshwater usage intensity (per barrel of bitumen produced) and its treatment compared to pure steam injection, thereby resulting in a reduced SOR. Furthermore, solvent injection contributes to declined GHG emissions intensities. According to the Oil Sands Emissions Limit Act, Alberta imposes restrictions on GHG emissions for bitumen production. Adding a solvent will reduce the need for energy-intensive steam generation, whose impact, relative to SAGD, is a 65% reduction in direct GHG emissions according to Canadian Energy Research Institute [14]. Despite the abovementioned benefits, some of the previous steamsolvent co-injection pilots have not performed well as per their design and/or execution. From the field projects listed in Table 1 below, important learnings included: z

Convincing laboratory experiments and/or reservoir simulations were not carried out for demonstrating the co-injection feasibility, particularly for heterogeneous reservoirs with lean zones and shale layers. Effects of reservoir heterogeneity on co-injection were not well understood.

z

The solvent that was used was too heavy and was injected for a too brief period of time (e.g., Nexen’s 2006 pilot).

z

The solvent concentration used was too low to be effective (e.g., Suncor’s Firebag 2005 pilot).

z

A pilot was conducted when the bitumen recovery was already so high that there was insufficient bitumen left for further economic recovery (e.g., Devon’s 2013 pilot).

z

Thorough sampling and study of produced fluids were not conducted for evaluating solvent recovery.

z

An appropriate adjustment of sub-cool during co-injection is not properly established.

z

A good baseline was not established with steady steam for proper comparison.

z

Steady operations were not performed for removing effects of variations in operating parameters.

z

A proper switching point to convert to normal SAGD to recover solvent was not well-founded.

CHOA JOURNAL — April 2022 40


This article summarizes our evaluations of several previous and potential industrial co-injection pilots in terms of a solvent type, solvent ratio, bitumen rate, and SOR. Particularly, lessons learnt from both successful and less successful co-injection pilots are provided. On these bases, specific recommendations on how to finely design steam-solvent coinjection strategies and pilots are presented to maximize the co-injection success opportunities.

ABSTRACT Table 1 summarizes several key industrial steam-solvent co-injection pilots conducted in Canada [15-17]. Solvents are divided into three main categories in terms of their volatility: light solvents (volatility comparable to C4 and lighter), heavy solvents (volatility comparable to C8 and heavier) and medium solvents (between the light and heavy categories). For multi-component solvents, an average molecular weight is used as the criterion to include them in one of these categories. As examples, Imperial Oil’s SA-SAGD Pilot, Connacher’s SAGD+ Pilot, and Suncor’s ESSAGD Pilot are analyzed.

Company and Project

Operating Pressure

Solvent

Imperial Oil SA-SAGD T13 Pilot The target reservoir in this pilot project was the Clearwater formation [18]. There were two horizontal well pairs (WP1 and WP2) and three observation wells per well pair in the pilot area. WP1 consisted of T1301 and T13-02 and WP2 was composed of T13-03 and T13-04 (Figure 1). Table 2 lists the basic parameters of this pilot. Under the operating pressure of 3,500 kPa, a solvent mixture (diluent composited of C3 to C10) was co-injected with steam at a concentration of 10 - 20% volume percentage. Solvent injection was first conducted in WP2 for around 26 months and then switched to WP1 to compare hydrocarbon production rates and SORs. A 30% bitumen rate uplift and 25% SOR reduction were achieved by the pilot. The solvent recovery reached 75% in WP2, and lower GHG emission intensity and water usage were reported. From Figure 2, during steam-solvent co-injection, the hydrocarbon production rate of WP2 was increased from 40 to 75 m3/day and its SOR dropped from 6 to less than 4 Sm3/Sm3. Similarly, adding a solvent mixture in steam increased the hydrocarbon production rate of WP1 from 30 to 50 m3/day and reduced its SOR from 5 to less than 3 Sm3/Sm3. Performance w.r.t. base SAGD

Concentration and Duration

Light

Medium

Heavy

Encana / Cenovus Senlac SAP (2002)

5000 kPa

C4

15 wt% for 7 months

Improved oil rate and SOR

NA

NA

Encana / Cenovus Christina Lake SAP (2004)

Not reported

C4

15 wt% for ~1 year (initial co-injection plan: 3 years)

Improved oil rate and SOR

NA

NA

Less than 25 wt% for ~2 years

Improved oil rate and SOR

NA

NA

Cenovus Christina Lake Variable (2200 C4 SAP (2009) to 2900 kPa) Nexen Long Lake ESSAGD (2006)

~1400 kPa

Jet B (consisting 5 vol% for 2 months of mainly C7 to C12)

NA

NA

No improvement observed

Imperial Oil Cold Lake SA-SAGD (2010)

~3500 kPa

Diluent (mixture of C3 to C10)

Up to 20 vol% for 8 months in WP-2 and then switched to WP-1

NA

Improved oil rate and SOR

NA

Connacher Algar SAGD+ Phase 1 (2011)

3500-4000 kPa

Condensate (consisting of mainly C4 to C8)

10 to 15 vol% for 5 months

NA

Improved oil rate and SOR

NA

Connacher Algar 3500-4000 SAGD+ Phase 1.5 (2012) kPa

Condensate (consisting of mainly C4 to C8)

10 to 15 vol% for ~ 3 years

NA

Improved oil rate and SOR

NA

Suncor Firebag ESSAGD (2005)

~2500 kPa

Naphtha (mixture of C7 to C9)

15 vol% in one well NA pair and 2 vol% in the other well pair

NA

Inconclusive

Conoco Phillips Surmont E-SAGD(2012)

~3500 kPa

A blend composed of mainly C3, C4, C6

18 vol% in one well pair and 20 vol% in the other well pair

Improved oil rate and SOR

Improved oil rate and SOR

NA

Devon JF SCI pilot (2013)

~2800 kPa

C6

Up to 20 vol%

NA

Reduced oil rate and steam

NA

Table 1: Summary of Previous Industrial Co-injection Pilots

41 CHOA JOURNAL — April 2022


“In our opinion, the Imperial Oil SA-SAGD Pilot has been one of the most successful SA-SAGD field trials so far; it performed successful SA-SAGD operations, 4D seismic monitoring, and simulated history matching.” To gain a comprehensive understanding of this SA-SAGD pilot, thermocouples and RST (reservoir saturation tool) logs were arranged to monitor temperature profiles and saturations. 4D seismic data was also acquired to compare the obtained temperature profiles. Moreover, laboratory experiments were carried out to evaluate the influencing factors and numerical simulations were performed to match the liquid production rate and SOR. In our opinion, the Imperial Oil SA-SAGD Pilot has been one of the most successful SA-SAGD field trials so far; it performed successful SA-SAGD operations, 4D seismic monitoring, and simulated history matching.

Reservoir oil

Bitumen

Operating pressure

3,500 kPa

Co-injected solvent

Mixture of C3-C10

Co-injection period

WP2: 2010/09/01 – 2012/06/15; WP1: 2012/04/01 – 2016/07/01

Solvent concentration

Up to 20 vol%

Table 2: Basic Parameters of the SA -SAGD T13 Pilot

Figure 1: Planar View of the SA-SAGD T13 Pilot Area (Data from AccuMap) [18]

Figure 2: Injection and Production Rates of the SA -SAGD T13 Pilot [18]

CHOA JOURNAL — April 2022 42


Connacher’s SAGD+ Pilot in Algar Well pairs 203-2 and 203-3 were chosen to conduct a light hydrocarbonsteam co-injection test (Phase 1) from July to November 2011 (Figure 3) [19]. At the very beginning, the solvent concentration was determined to be approximately 10 vol% and it was further increased to 15 vol% in October 2011. An increase of 28% in the bitumen production rate is shown in Figure 4. This corresponds to a reduction of 16% in the SOR after solvent injection when compared with the production data in April 2011. 89% of the injected solvent was recovered until April 2012. Another two well pairs (203-1 and 203-4) were selected for a second test (Phase 1.5) of the process from May 2012 to April 2015. Between May and August 2012, solvent injection was approximately 10 vol%. After that, the injection rates were adjusted down to around 6%, decreased to about 4% in March 2013, and further averaged to be 5.9% in 2014. It was discovered that the bitumen production rate rose by 30% and the SOR had a 32% decline during the period between May 2012 to April 2013 (Figure 4).

Figure 3: Planar View of Connacher’s SAGD+ Pilot Area (Data from AccuMap) [19]

Figure 4: Solvent Injection and Bitumen Production Rates for Connacher’s SAGD+ Pilot [19]

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Suncor’s ES-SAGD Pilot Four out of seven well pairs in Pad 109S were used for ES-SAGD (April 2019-May 2020) with a hydrocarbon co-injection concentration of 5-15 vol% (Figure 5) [20]. Pad 109S is located in the northeast of Suncor’s Firebag project with a hydrocarbon area of 1.5 MMm2, continuous reservoir thickness of 28.5m, porosity of 0.33, bitumen saturation of 0.77 and exploitable bitumen in place of 57 MMbbl. Until May 2020, the cumulative oil production in this pad was13 MMbbl and its recovery factor was 23%. With the co-injection of hydrocarbons, the bitumen production rates from the tested four well pairs were found to increase while the rates from other wells without solvent injection remained unchanged. In addition, early diluent return trends have been established. As shown in Figure 6, the oil rate increased by 40% while SOR decreased by 30%.

Figure 5: Planar View of Suncor’s ES-SAGD Pilot Area (Data from AccuMap) [20]

Figure 6: Oil Production Rate and SOR of ES-SAGD Wells for Suncor’s Pilot (Data from AccuMap)

CHOA JOURNAL — April 2022 44


Ongoing and Future Industrial Co-injection Pilots Ongoing and future industrial pilots will also provide both insight and inspiration into the application of steam-solvent co-injection. For example, Cenovus FCCL Ltd. has been operating a pilot at its Foster Creek W16 pad for over a year, MEG Energy Corp. has essentially completed an eMVAPEX pilot at its Christina Lake ‘A’ pad, and CNRL has conducted its ES-SAGD pilot at two G10 well pairs in Kirby, which reduces SOR by up to 50%. Suncor will continue their ES-SAGD development efforts in a second well pad in Firebag. Imperial’s planned SA-SAGD project in Aspen [21] will provide a valuable reference (Figure 7). As per their design, Imperial will operate at a bottom hole pressure of up to 3,400 kPa, and gas lifts will be used during the pilot start-up. The operation pressure will be reduced to around 2,500 kPa and the solvent concentration will be approximately 16.7 vol% during the pilot ramp-up. When the project comes to steady-state operations, the bottom hole pressure will be maintained between 1,000 to 2,500 kPa and the solvent concentration will stay the same. Imperial planned to inject a solvent mixture for ten years before the project wind-down. Imperial’s SA-SAGD design with a longer solvent co-injection period and a higher volumetric fraction of solvent might more substantially benefit steam-solvent co-injection performance. In addition to a proposed pilot at Aspen, Imperial has recently announced that their 10,000 b/d SA-SAGD project in the Grand Rapids Formation at Cold Lake is planned to be operational in 2025.

Figure 7: Aspen’s SA-SAGD Well Profiles [21]

45 CHOA JOURNAL — April 2022

“Ongoing and future industrial pilots will also provide both insight and inspiration into the application of steam-solvent co-injection.”


Lessons Learnt from Industrial Pilots Previous field pilots provided invaluable experience and knowledge in finely designing steam-solvent co-injection projects. For example, as addressed above, it is highly recommended that consistent monitoring, thorough sampling and accurate analysis of produced fluids are conducted in field tests to obtain a reliable value for solvent recovery, a good baseline is established with steam only to allow for proper comparison, pilot tests are operated in a steady manner with minimal operational interference to yield conclusive results, and the effects of reservoir heterogeneity on steamsolvent co-injection need be well understood.

Large bitumen holdings in Alberta are enormous and very important to the provincial and national economy, and Canadians are demanding their environmentally responsible recovery. In addition to addressing this environmental challenge, steam-solvent co-injection can have other potential benefits, such as reduced water usage, uplifted bitumen production rates, shorter project life, decreased SOR (energy intensity), higher ultimate recovery factors, reduced requirements for pipeline transportation, wider well spacing, operation in regions with operating pressure constraints, and unlocking currently uneconomical reservoirs. Extensive lessons have been learnt from the previous and current co-injection pilots and projects in the past 20 years and would significantly impact and accelerate the implementation of future field operations. It is now the critical time to move strategically from pilots to commercialization, especially in responding to Alberta’s recent regulations on industrial GHG pricing regulations and trading systems [23]. It might be advisable that laboratory experiments and reservoir simulation studies are performed before a new co-injection project is implemented, to demonstrate its co-injection feasibility, sensitivity analysis and economical gain, particularly for heterogeneous reservoirs with lean zones and significant barriers to flow, which can improve the success chance of the project and save its operational costs in millions.

“A viable steam-solvent coinjection strategy should follow several important guidelines”

More importantly, a viable steam-solvent co-injection strategy should follow several important guidelines [15, 22]: z

Solvent co-injection is mainly an acceleration process. An early start of co-injection expedites solvent benefits and allows enough time for its recovery after ceasing co-injection.

z

Terminating co-injection during the final stages of the process and continuing with pure steam injection provide sufficient time for solvent recovery.

z

Retained solvents can be partially re-evaporated with pure steam injection (due to increased average reservoir temperature), which can then be produced and recovered.

z

Occurrence of solvent re-evaporation can result in lower residual bitumen saturation inside a steam chamber compared to SAGD.

z

Solvents are injected in sufficiently high concentration to make an observable difference (preferably 10-15 vol%).

z

One selects a solvent that is light enough to travel in the reservoir as a vapor with steam but heavy enough to have high solubility in bitumen. In most cases, the solvent will need to have dominant constituents of C4, C5, and C6. Considering availability and costs, multicomponent solvents (e.g., gas condensates) are the practical choices for steam-solvent co-injection.

“It is now the critical time to move strategically from pilots to commercialization, especially in responding to Alberta’s recent regulations on industrial GHG pricing regulations and trading systems”

z

A pilot test must be of a sufficient size and duration to yield definitive results.

z

Convincing laboratory experiments and/or reservoir simulations are recommended to demonstrate the co-injection feasibility and perform sensitivity and economic analyses.

Acknowledgements

This article is partly support by an NSERC CRD project that consisted of the industrial partners Computer Modelling Group Ltd., Canadian Natural Resources Ltd., CNOOC International Ltd., Energi Simulation, PetroChina Canada Corp., and Suncor Energy Inc. The authors also thank the CHOA Editorial Committee for their valuable comments for improving this article. The authors wish to thank the CHOA Editorial Committee for their valuable comments in improving this article.

REFERENCES Comprehensive references for this article are located online.

CHOA JOURNAL — April 2022 46


Zhangxing (John) Chen holds the NSERC/Energi Simulation Industrial Research Chair and Alberta Innovates Industrial Chair and is a Killam Professor at the University of Calgary. His Ph.D. (1991) is from Purdue University, USA. He has authored/co-authored 25 books, published 1,000 research articles, and owned 30 patents. Dr. Chen is a Fellow of the Royal Society of Canada, Canadian Academy of Engineering and Energy Institute of Canada, and a Member of Chinese Academy of Engineering and European Union Academy of Sciences. He has received numerous prestigious awards, such as NSERC’s Synergy Award for Innovation, The Outstanding Leadership in Alberta Technology Award, IBM Faculty Award, and Fields-CAIMS Prize. His research interest is in Reservoir Engineering and Simulation and Renewable Energy. Ran Li is currently a research associate in the Reservoir Simulation Group at University of Calgary. She holds Ph.D. and master’s degrees in petroleum engineering from University of Calgary, and a bachelor’s degree in petroleum engineering from China University of Petroleum (East China). She has extensive industrial and academic project experience in oil sands and shale gas. Wei Wu is currently a Ph.D. student in the Department of Chemical and Petroleum Engineering at University of Calgary. Her research interests include thermal recovery, heat transfer, rock wettability, experimental measurements of water flooding, and reservoir simulation. She holds a M.Sc. degree in Petroleum Engineering from University of Calgary in 2017 and a B.Sc. degree in Geochemistry from Yangtze University. Sheng Yang holds a PhD degree in Petroleum Engineering from University of Calgary in 2018. His research interests include thermal recovery, artificial intelligence, tight reservoir simulation, and reservoir characterization. He has authored/coauthored over 30 technical papers. He holds a M.Sc. degree in Integrated Petroleum Geoscience from University of Alberta, a M.Sc. degree in Petroleum Geology from China University of Petroleum (Beijing) and a B.Sc. in Geophysics from Yangtze University. Jinze Xu holds Ph.D. and master’s degrees in petroleum engineering from University of Calgary, and a bachelor’s degree in petroleum engineering from China University of Geosciences (Beijing). He has more than five years of working experience in international oil and gas companies in Canada. Qiong Wang holds a Ph.D. degree in petroleum engineering from the University of Calgary and currently is a visiting scholar in the Reservoir Simulation Group at the University of Calgary. Her research interest is in improved heavy oil recovery methods and CCUS techno-economic analysis. Mohsen Keshavarz is currently a Project Economist within Suncor Energy’s Strategy and Corporate Development team. Formerly, he held reservoir and production engineering roles in Suncor. His research interests include analytical and numerical modeling of thermal and solvent-thermal recovery processes for heavy oil and oil sands. He is a registered professional engineer in Alberta and holds master’s and PhD degrees in petroleum engineering from the University of Alberta and the University of Calgary, respectively. Xiaohu Dong is currently an associate professor at the China University of Petroleum (Beijing). Previously, he was a post-doctoral fellow at the University of Calgary. His research interests include thermal/non-thermal heavy oil recovery techniques, multiphase flow in porous media, phase behavior of fluids in unconventional reservoirs, and EOR processes. He holds a PhD degree in petroleum engineering from the China University of Petroleum (Beijing). Xinfeng Jia currently works at China University of Petroleum (Beijing). He holds a PhD degree in petroleum engineering from University of Regina. His major research areas include thermal recovery of heavy oil, solvent assisted steam injection, and reservoir simulation. Min Yang currently works at China University of Petroleum (East China). She holds a PhD degree in petroleum engineering from University of Calgary. Her major research areas include thermal recovery of heavy oil, solvent assisted steam injection, in-situ combustion, and reservoir simulation. She has authored or coauthored over 20 refereed-journal articles and conference papers. Maojie Chai is currently a PhD student in the Reservoir Simulation Group at the University of Calgary. His research topic for his Ph.D. in petroleum engineering is concerned with the development of a dimethyl ether (DME) injection process for heavy oil recovery. His research interests include analytical and numerical modelling, phase behavior simulation and asphaltene precipitation forecasting. Dongqi Ji is a post-doctoral fellow at China University of Geosciences (Beijing) since 2020. His research interests are thermal, thermal-solvent, gas-assisted and electrical heating methods for heavy oil/oil sands recovery, as well as relevant numerical simulation software developments. He has a B.Eng. degree in petroleum engineering from China University of Petroleum (Beijing), and M.S. and Ph.D. degrees in petroleum engineering from University of Calgary.

47 CHOA JOURNAL — April 2022


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SEISMIC STRATEGIES FOR OIL SANDS With gratitude to the Canadian Society of Exploration Geophysicists (CSEG), CHOA is pleased to reprint a series of articles that demonstrates the practical application of geophysics in oil sands reservoir characterization and field development. The first article is entitled “Strategies to fill in the details for an oil sands reservoir: Kinosis example” and is authored by Dragana Todorovic-Marinic, David Gray and Jan Dewar. This paper describes the methodology and input used to build a detailed three-dimensional model of the Lower Cretaceous McMurray Formation in northeastern Alberta to position horizontal wells precisely and optimally. This objective was achieved by extracting as much information as possible from the seismic, using a suite of seismic attributes (e.g., spectral decomposition, dip azimuth, ant-tracking, curvature and density volume) to differentiate physical properties such as lithology, porosity, fluid type and fluid saturation. We hope this Essential Reprint can provide useful insights for your thinking about oil sands projects. Eugene Dembicki, CHOA Journal Editorial Committee

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Technical Topics Deadline to submit: 7 July 2022 Block 1: Transition in Exploration and Production Forum 1 - New supply sources to meet global energy demand Forum 2 - Innovations for cleaner production Forum 3 - Sustainable ways to maximise recovery Forum 4 - Carbon capture and storage Forum 5 - New technologies in geoscience

Block 2: Innovations for cleaner production Forum 6 - CO2 Utilisation and removal in products and processes Forum 7 - Emission reduction and recycling in refining & petrochemicals facilities Forum 8 - Cleaner fuels Forum 9 - Innovation in products

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TECHINCAL ARTICLE

A Systematic Multidisciplinary Approach for Optimization of Brownfield SAGD Projects - Part 2 BY SHAHBAZ MASIH, P. ENG. AND MARK SAVAGE P. L. GEO. INTRODUCTION This article is the second part of a two-part paper that focuses on a multidisciplinary optimization approach to drilling new well opportunities in existing pads. The first part, published in the February 2022 CHOA Journal, addressed optimization of existing pads by modifications in well completions and operational strategy. This article will focus on how a multidisciplinary approach can be used for adding infill wells, pad extension wells and/or farmer wells based on updated reservoir characterization, heat transfer, and other observations from operational performance data. It will also discuss how optimization of a brownfield project can be achieved for performance forecasting, well design and completions, facilities modifications for anticipated changes in steam requirement and treatment of produced fluids, and operational optimization of new wells by using a multidisciplinary approach.

Because regions of untapped heat transfer exist in a brownfield project, the benefits of continuous steam injection might not be fully realized due to limitations of existing well placement, steam generation, and fluid handling infrastructure. An updated reservoir characterization can identify regions of untapped heat transfer and lead to increasing brownfield oil rate and decreasing SOR through effective placement of new wells and/or upgraded infrastructure (as described in the first part of this article). These optimization changes may lead to adjustments in well completions, steam requirements, surface facilities, and future well completions (Figure 1).

Reservoir heterogeneity can present a challenge to efficient SAGD deployment, e.g., uneven heat distribution along the well length and in the reservoir during operation and optimization of Steam Assisted Gravity Drainage (SAGD). Based on analysis of geoscientific and well performance data, this inefficiency may lead to modifications in well completion and operational strategy, as discussed in the first part of this article. Optimization of brownfield projects directly targets increased oil rate and decreased steam oil ratio (SOR). The geological models (geomodels) used for numerical simulation of production and SOR forecasts, economic justification, and designing well pads and facilities depend on the quality of data from strat wells, seismic, geoscientific interpretation, and well performance. Analysis of geomodels and reservoir engineering interpretations is used to evaluate the optimal number of wells and well placement for the drainage area (Figure 1). However, the operation of SAGD wells and interpretations of 4-D seismic, vertical observation (Obs) well data, temperature logs, and continuous geoscience and reservoir/production engineering learnings, will give rise to updated reservoir characterization and/or geomodelling (Figure 1). Supplemental subsurface data (4-D seismic and Obs well data) can help identify reservoir pay thickness suitable for new well placement.

Figure 1: Impacts of Reservoir Characterization Updates

“An updated reservoir characterization can identify regions of untapped heat transfer and lead to increasing brownfield oil rate and decreasing SOR through effective placement of new wells and/or upgraded infrastructure” CHOA JOURNAL — April 2022 62


Operational Data Analysis and Changes/Updates in Reservoir Characterization Production performance of a SAGD operation depends on effective steam usage and heat transfer to bitumen. Steam mobilizes the bitumen along the steam chamber interface to facilitate gravity flow to the production well. In the early stages of a SAGD well pair’s life, temperature logs provide insight into heat distribution along the well length. Temperature logs along the production well length are the first indication of variable behaviour of permeability or heat conductivity in different reservoir facies. The reservoir facies originally considered to be permeable may in fact be a barrier or a baffle to convective heat propagation. Low quality reservoir facies may direct steam in unexpected ways, and lead to inefficient heat distribution and a higher SOR. Obs well data (temperature, pressure and/or saturation logging) is a useful tool to determine convective and conductive heat transmission in the reservoir. An additional advantage of Obs well data is its positioning relative to heat sourced from the SAGD injection well. Unlike temperature logs, Obs well data is not distorted by proximity to a heat source or to intermittent changes in steam injection or short-term shutdowns. 4-D seismic is another data type that aids in the analysis of reservoir heat distribution. The investigation volume measured with 4-D seismic is more expansive than either horizontal well log or vertical Obs well log data. Obs well temperature and saturation data and production well temperature data are used to calibrate 4-D seismic data. Analysis of calibrated 4-D seismic can be used to map steam transmission and heat transfer in the reservoir to identify new brownfield drilling opportunities.

Production data analysis may indicate premature coalescence of steam chambers and heat entrapment in places where existing SAGD well pairs cannot access mobilized bitumen. The analysis of 4-D seismic and Obs well data can identify where heated mobilized bitumen occurs that well pairs cannot access, e.g. outside the drainage area or between and below current producers. Identification of unaccessed mobilized bitumen presents the opportunity for drilling new infill, pad extension, and farmer wells (Figure 2). Incremental production provided by the additional new wells requires the deployment of increased steam capacity or reallocation of existing steam from suboptimal performing wells. Learnings from the operation of existing wells, operational data analysis, and updates in reservoir characterization can also identify supplemental optimization changes to brownfield well design, follow-up well completions, and artificial lift.

“Identification of unaccessed mobilized bitumen presents opportunity for drilling new infill, pad extension, and farmer wells”

The steam requirement increase may necessitate modifications in steam/ power generation system, water supply system, water treatment system, and water disposal system (Figure 2). The increase in produced fluid may lead to changes in oil treatment system, bitumen storage and delivery system, produced gas volume, water treatment, and disposal systems (Figure 2). The description of these major systems and the disciplines responsible have been described in the first part of this article. The discussion section of this article will describe three types of additional brownfield wells and corresponding operational learnings that lead to the addition of these wells. It will also describe how new learnings can impact operation/modification of major components of a SAGD project (Figure 2) and how to handle those changes and finally, operational optimization of new wells in a multidisciplinary approach.

Figure 2: Additional wells and their impact on main components of SAGD system

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Figure 3: Infill Wells – Simplified Plan View

Figure 4: Infill Wells – Conceptual Cross-Sectional View

DISCUSSION Example 1 - Infill Wells Infill wells are horizontal producers placed between producing SAGD well pairs to access a wedge of heated bitumen (Figures 3 and 4). The timing and placement of infill wells (horizontal and vertical) are a function of: z

reservoir characteristics (saturation and permeability),

z

reservoir architecture (thickness, structure, and degree of heterogeneity), and

z

interwell spacing and performance (steam chamber conformance and production) of existing well pairs and facility steam and fluid handling capabilities.

Optimal timing and number of infill wells per pad involves multidisciplinary input from geoscience, reservoir and production engineering, drilling and completions (D&C), and operations and maintenance (O&M). O&M and production engineering manage the existing SAGD well pairs’ daily production; for example, steam requirements, production rate, and fluid processing. The optimal timing of an infill well’s first production is influenced by O&M along with production and reservoir engineering in assessing future steam and fluid handling demand versus available steam and fluid handling capacity. Steam and fluid handling capacity is influenced by the actual performance of the existing well pairs (fluid rates and SOR), versus the predicted and potential forecasted range (Figure 5), and by the limitations of surface facilities. If SOR is higher than predicted, steam availability may become a limiting factor, thereby influencing the timing and number of infill wells.

Figure 5: Conceptual SAGD Well Pair Performance – Predicted (Black line) vs Actual (Solid Dark Green line) vs Forecasts (Dashed Light Green lines)

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Figure 6: SAGD Obs Well Temperature Data over Time (Source: AER D54 2019 8668) Gamma Ray (Black line), temperature timelines: timeline 1(Gray line), timeline 2 (Purple line), timeline 3 (green line), and timeline 4 (red line). Reservoir and production engineering analyze daily operational data from SAGD well pairs and Obs wells (Figure 6), to track, interpret, and estimate steam chamber development and the coalescence timing of adjacent chambers. Coalescence of steam chambers in adjacent well pairs is indicated by similar steam chamber pressure trends or equal steam chamber pressures. This can lead to heat transfer outside the drainage area and provides little or no contribution to bitumen recovery. Continuous steam injection for 3 to 4 years can lead to accumulation of heat and mobilized bitumen in the reservoir between two adjacent well pairs that is inaccessible to existing producers and leads to increased SOR. Reservoir characterization updated with revised interpretations from 4-D seismic and Obs well data can indicate favourable conditions for the placement and production of new infill wells. Geomodels (Figure 1), updated by geoscience can help reservoir engineering improve field production forecasts, and estimates of steam and production handling requirements; for example, the amount of additional oil and water to be treated, additional diluent and disposal requirements, and the additional capacity for bitumen storage and delivery (Figure 2). Typically, all these variables lead to a first oil window during the early to mid plateau stage of a drainage area’s productive life. D&C should involve the collaborative input of reservoir and production engineering and geoscience in the well design and selection of artificial lift. Infill well placement planning is a collaborative effort involving geoscience, reservoir and production engineering, and D&C. The horizontal placement of infills is typically equidistant between producing well pairs (Figure 3). Vertical placement is influenced by architecture and characteristics of reservoir geology, SAGD well pair producer trajectory, and corporate stand-off philosophy (i.e., height above base of pay or bottom water), Figure 7. Key reservoir considerations influencing the infill’s vertical placement are the base of pay structure (elevation and directional trend) and nature of the contact (mudstone/non-pay, Devonian carbonates, or bottom water), presence of high mobility zones, e.g., transition or lean zones, and the degree and placement of reservoir heterogeneity (Figure 7). Operational considerations influence the stand-off height considering the impact of heat loss on SOR and water cut.

Figure 7: Infill Wells – Vertical Placement Relative to SAGD Well Pair

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Optimal vertical well placement is unique, it is rare for two infills to be positioned the same (Figure 7). Vertical placement influences infill economics and the proportion of accelerated versus incremental reserves. The lower the infill well is placed relative to the SAGD producer, the more incremental reserves can be produced. Economic and operational analysis will justify the number and timing of infill wells. The plan of each infill well trajectory involves collaborative work by geoscience, reservoir, and production engineering, and D&C. To optimize the infill’s vertical position requires integrated interpretation of geoscience data, updated geomodel and reservoir engineering simulations, steam chamber conformance, and heat transfer analysis from 4-D seismic, Obs well data and temperature logs and, existing well pair performance. Operational Optimization of Infill Wells Infill well performance depends on its level of connectivity to heated bitumen between coalesced steam chambers. For start-up of infill wells, establishment of connection may require multiple periods of cyclic steam stimulation and demand availability of temporary infrastructure (e.g., temporary steam lines and supporting well completions) for switching the well from injector to producer. The existence of high mobility transition and lean bitumen zones in the vicinity, reservoir heterogeneity, and the amount of innate heat due to steam injection in the adjacent injectors may impact the start-up process.

“... it is rare for two infills to be positioned the same ...”

Infill well start-up is considered almost complete when it has established communication with drainage caused by the overlying steam chamber as indicated by produced fluid temperatures, production continuity, and other operational data. The infill well creates its own drainage mechanism and will alter the steam chamber shape of adjacent well pairs. The heat source for infill well production comes from steam injectors in adjacent well pairs. Fluid rates and SOR performance data of adjacent well pairs and infill wells should be analyzed in combination for optimization purposes. The connection of an infill well to the steam chamber may lead to changes in steam chamber pressure and thereby change steam injection rates in the adjacent injectors. Changes in steam injection rates and production from an infill well can also necessitate changes in operational and artificial lift design in adjacent producers due to their impact on volumes drained from the steam chamber. Analysis of steam allocation by reservoir engineering is required where steam shortages or other plant issues that pre-exist an infill well could impact steam availability and fluid handling capacity. In conclusion, additional production from an infill well may cause changes in all major components of a SAGD brownfield project (Figure 2).

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Figure 8: Pad Extension Well Pair – Plan View

Figure 9: Pad Extension Well Pair – Cross-Section View

Example 2 - Pad Extension Well Pairs

system, and storage and delivery systems (Figure 2).

Pad Extension well pairs are SAGD well pairs (injector and producer) placed outside the original drainage area to access incremental bitumen (Figures 8 and 9). The timing and placement (horizontal and vertical) of these wells are a function of multiple parameters, as is in the case of infills.

The updated reservoir characterization data, geomodels and learnings from operational data may lead to modifications in well completions, e.g., placement and type of flow control devices and artificial lift design, for both injector and producer of the extension well pair (Figure 1), and may require coordination between multidisciplinary teams as explained in the infill wells section. The placement of extension well pairs is influenced by reservoir geology and the trajectories of existing well pairs, and is also handled by a multidisciplinary approach as explained in infills section.

To assess pad extension wells’ optimal placement and develop performance forecasts requires a multidisciplinary effort, as is outlined for infills in the previous section. A pad extension well pair is usually drilled to access part of the reservoir that was previously considered not suitable for SAGD operation. Updates in reservoir characterization data from temperature logs, Obs well data and 4-D seismic data, and operational data may identify an opportunity for a new well pair outside the original drainage area. For example, 4-D seismic, operational data and/or updated facies characterization may indicate thicker pay close to the original drainage area. Existing production data can also be used for history matching, for reservoir parameters, and for fine-tuning and generation of performance type curves in reservoir simulations. Optimal timing of first production is predicted with O&M and production engineering assessment of future steam and fluid handling requirements, compared to availability. The steam requirement for a pad extension well pair could be like the offset well pairs, and considerably higher than an infill well. If existing well pair SOR is higher than predicted, steam availability may be limited, thereby influencing the timing for start-up of pad extension well pairs. The extra volume of steam and produced fluids may require modifications in the steam generation system, oil and water treatment systems, the disposal

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Operational Optimization of Pad Extension Wells Start-up and SAGD operational phase of the well life cycle can also be enhanced from the learnings of other wells in the same pad or from other pads in the same field (Figure 1). The multidisciplinary approach for optimization of the pad extension wells can be utilized as explained in the first part of this article.

“Updates in reservoir characterization data ... may identify an opportunity for a new well pair outside the original drainage area.”


Figure 10: Sidetrack Farmer Well – Longitudinal Cross-Section View Example 3 – Farmer Wells Farmer wells differ from infill wells, in that they are sidetracked horizontal producers placed below the SAGD well pair producer to access heated bitumen (Figures 10 and 11). The heated bitumen can be identified from Obs well and 4-D seismic data. The presence of untapped mobilized bitumen below the producer may also be identified from updated geoscience reservoir characterization and learnings from drilling (for example, stand-off height) and operations of the existing well pairs. The optimal timing for farmer wells is the wind-down stage. The horizontal and vertical placement, completion and operation of farmer wells require a multidisciplinary effort similar to infill and extension wells, and as explained in the previous infill well section. The key difference for farmer wells is the interpretation and mapping of the heated bitumen zone below the producer’s elevation and the zone’s areal extent. The interpretation of heated bitumen regions using 4-D seismic with 3-component geophones profoundly improves optimization of farmer well placement. In general terms, and dependent upon reservoir quality, saturation, and vertical placement, the ability to put a producer well lower across a drainage area could equate to an additional range in recoverable bitumen of 300,000 to 800,000 barrels.

Figure 11: Sidetrack Farmer Well – Perpendicular Cross-Section View

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“The optimal strategy requires collaborative input from geoscience, reservoir and production engineering, D&C and O&M. The potential of interpreted 4-D seismic to identify and enhance assessment of prospective incremental reserves and improve well placement ... significantly outweighs the cost of seismic acquisition and processing.” Operational Optimization of Farmer Wells

Conclusion

To our knowledge, farmer wells have not yet been deployed in the field, so operational predictions are made based on the author’s experience from infills, extension wells, and SAGD well pairs. Similar to an infill well, the start up of a farmer well will depend upon the amount of heat present along the well’s trajectory, and access to drainage from an overlying steam chamber. The closer proximity of a farmer well to its SAGD well pair, compared an infill well, can heighten communication with bitumen mobilized by conduction below the overlying steam chamber. If a farmer well is placed in immobile bitumen, it may need cyclic steam stimulation to establish communication with the overlying steam chamber. Operating a farmer well can be similar to operating a SAGD producer well, once fluid temperature and production rate indicate farmer well start up is complete. Any production from farmer wells will increase the steam chamber volume. As a result, in order to achieve a targeted steam chamber pressure, planning for an increased steam volume may be required.

Optimization of brownfield pads or individual wells comes in many forms and with multiple options. The appropriate optimization components can vary across a drainage area or an entire field. The optimal strategy requires collaborative input from geoscience, reservoir and production engineering, D&C and O&M.

Impacts on the main components of a SAGD brownfield operation (Figure 2), can be optimized by using a multidisciplinary approach, as was discussed the first part of this article.

The potential of interpreted 4-D seismic to identify and enhance assessment of prospective incremental reserves and improve well placement of one of the three well types (infill, pad extension or farmer) significantly outweighs the cost of seismic acquisition and processing. Ongoing updates of the reservoir characterization process during the ramp-up and plateau stages with new geoscientific data and operational learnings can enhance economic viability of remedial action. A collaborative multidisciplinary process with defined roles and responsibilities will enhance understanding of which additional well type (infill, pad extension or farmer wells) is most advantageous for a drainage area.

ACKNOWLEDGEMENT Input provided by Gordon T. Stabb, P. Geol., towards writing this article is greatly appreciated. The authors thank Gordon for his long-serving support of CHOA and our industry.

Shahbaz Masih, P. Eng.

Shahbaz Masih is an APEGA-registered professional engineer with a Master in Data Science and Analytics from the University of Calgary, and an M.Sc. from the University of Regina (Canada) and a B.Sc. from UET Lahore (Pakistan), both in Petroleum Engineering. He has worked in the Canadian oil industry for more than ten years with Cenovus Energy, Statoil Canada Ltd., and Sunshine Oilsands Ltd. And Dynamic Risk Assessment Systems. Highlights of his work experience include financial modeling, machine learning, data analytics, project development through economic analysis, operational optimization through reservoir and production engineering techniques and an NSERC research project focused on porous media flow in SAGD. Shahbaz is currently working as a lead data scientist at ATB Financial. 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 OilCorporation. He has collaborated on and led in situ geoscience, operations and development teams.

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TECHINCAL ARTICLE

Carbon Capture and Storage: A Critical Pathway to Net-Zero BY RYAN THON, EIT AND DIANA HAIKAL, EIT

INTRODUCTION Carbon capture and storage (CCS) is an important emissions-reduction process that can be applied across multiple industries. CCS is one of the solutions to reduce carbon emissions while the use of fossil fuels continues during the energy transition. To meet net-zero emissions targets, the deployment of CCS technology globally is critical. CCS involves technologies for the capture of carbon dioxide (CO2) from fuel combustion, industrial processes, and from the air (direct air capture - DAC) — separating the CO2 from other gases before it is emitted into the atmosphere (or afterward, in the case of DAC), thus reducing the overall carbon dioxide emissions. While CCS is part of the solution, a range of other methods are required to effectively decarbonize including electrification of equipment, renewable energy, and energy efficient technologies. The gains that can be achieved by the use of energy efficient technologies, renewables and electrification alone, however, will not be sufficient to achieve net-zero goals. CCS will play an essential role due to its inherent characteristics: it is a straightforward and effective carbon reduction approach; CCS can be retrofitted to existing complexes and stationary sources to treat flue gases and allow them to function cleanly for their design life; and is one of the few technologies able to adequately displace CO2 from coal or gas-fired power generation and large-scale emissions from industrial sources.

“CCS will play an essential role due to its inherent characteristics: it is a straightforward and effective carbon reduction approach”

Capturing the CO2, however, is only part of the equation. Permanent storage of CO2 in subsurface geological formations is critical to achieving large-scale emission reductions. According to analysis of net-zero pathways by the International Energy Agency (IEA), the storage of CO2 is required to increase by over two orders of magnitude to maintain emission reduction targets -- from 40 Megatonnes (Mt)/year today to over 5,000 Mt/year by mid-century. There are several options for the permanent geological storage of CO2, ranging from injection into depleted hydrocarbon reservoirs, injection into actively producing hydrocarbon reservoirs for Enhanced Oil Recovery (EOR), and injection into saline aquifers. As deep saline aquifers are commonly found around the globe, occupying vast volumes of pore space, they hold the highest potential for future geological CO2 storage.

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“As deep saline aquifers are commonly found around the globe, occupying vast volumes of pore space, they hold the highest potential for future geological CO2 storage.”

Saline aquifers are layers of porous sedimentary rocks (typically sandstone or carbonate) saturated with a salt-water mixture known as brine that CO2 can be injected into (in Alberta, aquifers with a salinity greater than 4,000 mg/l are defined as ‘saline’). CO2 either mixes within the brine, reacts with dissolved minerals, or gets trapped in pore spaces. Typically, 800 m is the minimum depth for geological storage as at this depth CO2 is at its critical pressure (73.8 bar) due to the hydrostatic gradient. In Western Canada, CO2 is also commonly used as a reservoir flooding agent for EOR in mature fields that have previously been produced by primary and subsequently secondary recovery methods (such as waterflooding). In a CO2 flood, CO2 is injected into mature reservoirs that typically have oil recovery in the range of 20-40% of the original oil in place (OOIP) and therefore have substantial oil remaining. The CO2 is injected either continuously, or as water-alternating-gas (WAG) sequence. While much of the CO2 used in EOR is produced and recycled back into the reservoir, the process is a net sink for CO2 as the CO2 is used for voidage replacement and, ultimately, permanent sequestration. A 2009 report by the Alberta Economic Development Authority (AEDA) estimated that 20-30 million tons of CO2 could be sequestered using EOR every year at peak operation in Alberta.

“A 2009 report by the Alberta Economic Development Authority (AEDA) estimated that 20-30 million tons of CO2 could be sequestered using EOR every year at peak operation in Alberta.”


CARBON CAPTURE TECHNOLOGIES Before CO2 is stored or utilized in downstream production, it can be captured through various means. The capture of CO2 is generally categorized into pre-combustion, oxyfuel combustion and postcombustion. Pre-combustion capture methods include natural gas sweetening or syngas (gaseous mixture of H2, CO and CO2) produced from reforming and gasification processes. Oxyfuel combustion uses pure oxygen instead of air in a combustion reaction to produce an exhaust stream containing CO2 and H2O. It includes technologies such as chemical looping, which uses metal oxides as oxygen carriers for the combustion process. Post-combustion technologies remove CO2 from flue gases after the combustion process has occurred. Post-combustion is often the best solution for existing facilities as they can be retrofitted on the back end to capture the flue gas, minimizing disruption to ongoing operation. Within the capture categories mentioned above, there exists a range of technologies at various Technology Readiness Levels (TRL). The major types of technologies include liquid absorbents (1st / 2nd generation solvents), adsorbents, membranes, high-temperature solid looping, cryogenic processes as well as processes where the CO2 is inherently captured (Allam-Fetvedt Cycle, Calix Advanced Calciner).

CLIMATE COMMITMENTS AND ACTIONS Environmental Canada has committed to various climate goals and initiatives in the pursuit of reducing emissions that impact its energy sector. In 2015, Canada signed on to the Paris Agreement with the goal to limit global warming to 1.5°C in comparison to pre-industrial levels. Canada specifically committed to reducing its greenhouse gas emissions by 30% by 2030. Additionally, Canada committed to achieving net-zero emissions by 2050 under the Canadian Net-Zero Emissions Accountability Act, which establishes 5-year emission reduction goals. As part of this effort, increases in energy efficiency and the implementation of renewable energy sources will be required; however, the deployment of CCS technology will be critical if Canada is to continue to benefit from the economic prosperity that derives from our energy sector.

“... the deployment of CCS technology will be critical if Canada is to continue to benefit from the economic prosperity that derives from our energy sector.” The Oil Sands make up about 25% of Alberta’s annual greenhouse gas (GHG) emissions with approximately 70Mt released annually. As part of the effort to curb emissions, Alberta has legislated a maximum of 100Mt release for any year moving forward; this provides producing companies

adequate time to work toward emission reduction targets, with a major focus on advancing CCS solutions. To help achieve meaningful emission reductions, Alberta has also implemented a Technology Innovation and Emission Reduction (TIER) Regulation for emitters that release more than 100,000 tonnes of CO2 annually. Under the TIER system, large-scale emitters are required to lower their carbon emissions by 10% compared to baseline standards set in 2013-2015. If emitters under the TIER system release more than their baseline, they are required to pay a carbon tax of $30 per tonne of CO2. If they release less than their baseline, they earn emission credits. Currently, environmental restrictions on large emitters are tightening by 1% annually beginning in 2021 (emitters must follow 89% free allocation in 2021, 88% in 2022, and so on). This drives companies under the regulations to invest in emission reduction technologies, as the efficiency of processes can only be improved by so much. For producing companies in Alberta, the only practical way to continue to increase production while meeting more stringent regulations is to invest in carbon capturing technologies.

“... the only practical way to continue to increase production while meeting more stringent regulations is to invest in carbon capturing technologies.”

Economic Costs associated with carbon capture must be considered by large emitters before any plans for implementation are finalized. A brief breakdown of costs to be considered: z

Cost of capturing the CO2 itself. Costs are dependent on the concentration and pressure of the CO2 emission stream. Problems may arise with energy penalties from the parasitic load of the carbon capture equipment itself, maturity of technology and need for further research and development.

z

Costs associated with compression and dehydration of emission streams.

z

Distance between emission sites and storage. There are costs associated with the transportation of CO2 through pipelines or other means of transportation. It is economically appealing to develop major CCS hubs and storage sites in areas of higher industrial activity.

z

Costs associated with the injection of CO2 into wells. This depends on well location (offshore/onshore), reservoir depth and injection rate.

z

Monitoring costs that are dependent on regulatory requirements and injected CO2 plume size.

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Figure 1: Rising Carbon Tax Price Source: Government of Canada website - https://www.canada.ca/en/environment-climate-change/services/ climate-change/pricing-pollution-how-it-will-work/carbon-pollution-pricing-federal-benchmark-information.html In Alberta, the largest economic driver for the implementation of carbon looking to implement CCS, Alberta has grant programs in place. Alberta capture is the rising tax on carbon emissions. Alberta follows the federal implemented the Industrial Energy Efficiency and Carbon capture government plan, the Federal Fuel Charge, to progressively raise the and storage (IEE CCS) Grant Program as an investment to help fund carbon tax each year until it reaches a maximum of $170 per tonne by the projects that reduce emissions and improve energy efficiency. It has year 2030 (as currently planned). been observed that the IEE CCS The schedule of rising carbon tax allocation of funding has increased price per tonne is summarized from $80 million to $131 million in Figure 1. The carbon tax price in 2020 and 2021 respectively, increases on April 1 of each year. indicating government support globally for the development of Without programs such as TIER projects to reduce emissions. available, large emitters would It has since gained additional be paying 4.25 times more per momentum as more projects have tonne of carbon a decade from been selected to receive funding. As of early 2022, a new $30-million fund now. Fortunately, under the Alberta TIER system, oil sands emitters can is being provided to Emissions Reduction Alberta (ERA) from the TIER be exempt from paying up to 90% of the Federal Fuel Charge. Facilities fund to support and accelerate pre-construction design and engineering are compared to similar product specific benchmarks, which results initiatives. in stronger performers earning credits while poorer performers will

“... the largest economic driver for the implementation of carbon capture is the rising tax on carbon emissions.”

owe more to meet TIER compliance. Facilities that reduce emissions beyond their benchmark can generate performance credits. Facilities that do not meet the emission reduction requirement will be required to contribute to the TIER fund for each tonne of excess emissions or submit purchased performance credits that were generated by another facility. As there is a maximum proportion of compliance that can be covered by performance credits, facilities are further encouraged to sell their credits to underperforming facilities to meet their benchmark before their credits expire. For producers planning to either maintain their annual production or increase it over time, or for those who have made commitments to achieve net-zero emissions, it will be necessary to implement greenhouse gas emission reduction methods. For existing facilities, this can most easily be achieved with minimal disruption to operations by retrofitting with carbon capture equipment. To support companies

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Social There is also a corporate social responsibility to support and contribute to society in a manner that benefits all. The concept of social responsibility lies in a company conducting its business activities, while remaining profitable, and voluntarily recognizing the impact of its operations on the environment and the public. The Canadian energy industry’s participation in carbon tax and the TIER program is a step in the right direction to reducing GHG emissions on a large scale. Multiple companies have already taken a step to working together with the government to achieve the goal of net-zero greenhouse gas emissions. Recently, the Pathways to Net-Zero Alliance was announced which currently includes Canadian Natural Resources Limited, Cenovus Energy, ConocoPhillips, Imperial, MEG Energy and Suncor Energy with the aim to incorporate several parallel pathways to address GHG emissions – carbon capture is expected to play a major role for the Alliance members.


“With the increased scrutiny that society places on the environmental impacts of large oil and gas companies, those that strive toward investment in renewable energy and emission reduction programs display leadership and gain the social license to operate.” To meet the increasingly stringent environmental regulations on corporations under the TIER program, investment in research and development (R&D) is essential. Through R&D efforts, CCS technologies are becoming more efficient and cost-effective, which allows companies to simultaneously grow and reduce emissions. With the increased scrutiny that society places on the environmental impacts of large oil and gas companies, those that strive toward investment in renewable energy and emission reduction programs display leadership and gain the social license to operate. While individual actions are important, corporations can push for policy changes, influence the actions of consumers, and respond to the need for reduced carbon emissions at a significantly larger scale and quicker pace.

CONCLUSION The TIER program was implemented to help companies reach their commitments to net-zero emissions. Participation in the TIER program demonstrates a social responsibility to reduce emissions and alleviate their environmental impact. Companies benefit economically by participating in the TIER program and, through government grants, are encouraged to develop technology and retrofit their facilities with carbon capture technology. The road to net-zero emissions is long and requires facilities to collectively do their part. By integrating scientific-technical evaluation and socioeconomic analysis into projects from conceptual development and directing the focus on the three pillars of sustainability, companies will be able to reduce emissions, continue to grow, and remain profitable.

Ryan Thon, Process Engineer in Training

Ryan graduated with a bachelor’s degree in chemical engineering from the University of Calgary in 2021. He is passionate about the energy and manufacturing industries, with a drive to accumulate additional knowledge about these rapidly evolving sectors. You can find Ryan spending his time in the mountains and hunting down the best craft beers in Alberta.

Diana Haikal, Process Engineer in Training

Diana is a process engineer in the Hatch Oil & Gas business unit with a B.Sc. degree in Chemical Engineering from the University of Calgary. Her passions include RAM analysis, and CCS technologies. In her free time, she is outdoors enjoying what nature has to offer.

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In the 1920s and 1930s, Bitumen was touted as “Nature’s Supreme Gift to Industry” – a marvellous investment opportunity for the bold. A century later, the oil sands still need massive creativity, epic perseverance, and bold investments, to address climate change, shifting investment patterns, and ”keep it in the ground.” Bitumen beyond combustion, to make valuable products instead of burning refined bitumen as fuel. Carbon dioxide sequestration on an industry-wide scale never before seen. Deep Indigenous partnerships as a model for the world. Bitumen as Nature’s Supreme Gift to Humanity for the next centuries. CHOA JOURNAL — April 2022 80


April 2022


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