Journal of the Canadian Heavy Oil Association - Winter Edition 2019

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FEATURE ARTICLE Curtailment - A Tactic Not a Strategy p.12

Special Feature: Celebrating CHOA’s Fall Conference p.08



WHITE PAPER Cash in the Barrel: Working Capital Management in the Oil & Gas Industry p.22





Message from the President


CHOA Member Profile

Gerald Bruce


CHOA Celebrates 30 Years in Heavy Oil


ABOUT THE CANADIAN HEAVY OIL ASSOCIATION The mission of the Canadian Heavy Oil Assocation is to provide an appropriate technical, educational, and social forum for those employed in, or associated with, the heavy oil and oilsands industries.



Feature Article Curtailment - A Tactic Not A Strategy By Caralyn Bennett


White Paper

Cash in the Barrel: Working Capital Management in the Oil & Gas Industry


CHOA Member Profile

Uliana Romanova


Sponsor Feature

Baker Hughes


Technical Article Firebag’s Journey to Digital Twin: Firebag SAGD

Reservoir Simulation Platform By Jinze Xu, Jin Wang, Hossein Aghabarati, Amir Zamani, Kathy Cheung

Suncor Energy Inc.


Sponsor Feature

GLJ Petroleum Consultants



Board of Directors



CHOA Sponsors





UPCOMING EVENTS NETWORK with other industry professionals through our Member Exclusive “SOCIAL LINK“ platform where you can create your own groups for collaboration, connect with mentors or expand your circle. SAVE ON Social & Technical events and Workshops EXCLUSIVE MEMBER RESORCES like our Special Monthly Update and The CHOA Journal



January 16, 2020

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BECOME A CHOA MEMBER TODAY! CHOA membership has big benefits, including an outstanding technical program in a variety of formats, popular networking events, access to the Journal and members-only sections of, discounts, for events and workshops, and the opportunity to apply for annual scholarships for CHOA members and family. Most importantly, CHOA membership provides the opportunity to belong to a heavy oil community and contribute to an organization dedicated to improving knowledge on heavy oil and oilsands issues.




MESSAGE FROM CHOA’S PRESIDENT CARALYN BENNETT Three key areas, each important on its own, have been identified, and these will continue to be our areas of focus into 2020.

Let’s begin with gratitude. The CHOA knows there is a decision to be made for each and every dollar spent by our members and sponsors, especially in view of the most recent round of belt-tightening, and we want to take a moment to thank all of you for your support at all of our events throughout the year. Together, our members, volunteers, speakers & panelists, event attendees and corporate and event sponsors are what allow us to continue to deliver on our mandate.

What is our mandate? Why does the CHOA exist as

an organization? Thirty years ago, our organization was created because of the immense heavy oil and oil sands resource in Canada and because of the challenges the industry faced at that time in developing those resources. Through our content and programs, including the CHOA Journal, business conferences, technical luncheons, and well-attended professional development and networking events, the CHOA has played a key role bringing people together to share insights, knowledge and technology in order to effectively tackle the challenges. This started with the development of recovery process technology to commercially extract our resources and, more recently, has focused on technologies aimed at enhancing our sustainability and improving our competitiveness. Thirty years later, the reasons for our existence remain the same. We still have a tremendous resource and we are still faced with numerous challenges. But the challenges today are different and the solutions we develop as an industry will also be different. For this reason, our organization must also evolve; we must modernize in order to continue to be effective in our mandate.

First, in line with our legacy, technology and innovation will play a key role in our future; but today, the necessary pace of change requires us to get “out of our box” and engage beyond our subsector and potentially even beyond our industry. Most recently, the CHOA brought together 170 diverse industry professionals at our 2019 Fall Conference “30 Together for the Future” to identify and discuss the steps we need to take; Michele Squires’ presentation on the Water Technology Development Centre stood out as a collaborative effort aimed at speeding up the time it takes to get new water technologies into operation. Along similar lines, the CHOA is a part of the CRIN initiative “Accelerating Novel Hydrocarbon Recovery Technology Development” currently underway. Second, to ensure our future, we need to be attracting the brightest young minds to our industry and our organization. The CHOA’s Developing Professionals events are geared towards planting seeds and also offering opportunities for this very important demographic to make a difference to both our industry and the world. This past year we kicked off our “Getting to Know an industry leader” series, held an engaging panel event on Changing the Discussion: How to Talk About Oil and Gas and, most recently, collaborated with four other young professional groups to host the Young Professional Christmas Party. Third, we need to take ownership and find a way to speak up for our industry, Canada’s energy sector. We need to do our part to learn and to educate and to share our stories about the importance of our industry to society, specifically, our efforts and successes in the areas of ESG and sustainability. Please check out and subscribe to our new podcast


series, Over A Barrel, hosted by our dynamic CHOA board member, Louisa DeCarlo. As we look towards 2020, the CHOA can be a part of finding common ground and through our membership, we can also be a part of building bridges to Canadians outside of our industry. On behalf of the CHOA, I would once again like to thank you all for your attendance, sponsorship, and continued support. Stay safe, enjoy the holidays and we’ll see you at our next event.



Leveraging insights from East and West, we produce energy around the world safely, responsibly and ethically. We are committed to developing our assets in a way that ensures long-term sustainability.

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2019-12-13 9:04 AM





Past President Long-time Volunteer



Moved around the country 7 times


My dream is to build a brand new bitumen processing facility in Alberta.

engineer in the refining and heavy oil sector

Gerald BRUCE, CHOA Past President Gerald Bruce has spent a lifetime in the refining and heavy oil sector in Canada. He started his career with Petro-Canada, worked for Jacobs Engineering and retired from MEG Energy. Today, though in retirement, he is as busy as ever working with a start up and a consulting company and is still very active with volunteer commitments. Gerald started his career by following in his father’s footsteps and becoming a chemical engineer.

“I have refining in my blood.”





GERALD BRUCE Gerald Bruce has spent a lifetime in the refining and heavy oil sector in Canada. He started his career with PetroCanada, worked for Jacobs Engineering and retired from MEG Energy.

Today, though in retirement, he is as busy as ever working with a start up and a consulting company and is still very active with volunteer commitments. Gerald started his career by following in his father’s footsteps and becoming as a chemical engineer.

“My passion is ensuing the industry in Alberta is relevant and we can position ourselves to be the supplier of bitumen for the world,” said Gerald. “My dream is to build a brand-new refinery in Alberta.” And for that reason, his involvement in CHOA is a great fit.

“I have refining in my blood,” he explains. Involvement with CHOA His father started the Texaco refinery in 1949 in Edmonton and was involved in shut down in 1984. Although Gerald grew up in Montreal (where his father was based), he completed his university degree in Waterloo, Ontario and then moved to Alberta to work on the Esso Cold Lake project as part of his work terms. He made Calgary his home and stayed “because the skiing was good, and the opportunities were good.” 32 Year Career With a strong background in refining, Gerald spent 23 years with Petro-Canada moving several times across the country as different opportunities came up, but he always returned to Calgary. Then he became a subject matter expert in a role with Jacobs Engineering focused on the oil sands and that translated into work with MEG Energy working on a partial upgrading technology. Gerald retired in 2013 after 32 years in the oil and gas industry but chose to stay involved through different initiatives that include technology development and applications, heavy oil production and bitumen market accesses initiatives, including solidification.

Gerald started with CHOA in 2004 as a volunteer on a technical subcommittee and he became the CHOA Vice President, and then President. He is still very active with CHOA and sits on the Facilities and Upgrading Technical Subcommittee and manages the CHOA LinkedIn Group which has over 5800 members. “CHOA is unique,” said Gerald. “You are able to have a cross section of the different people involved within different sectors of the industry from producing, moving, and processing oil to service support. It really helps to build an appreciation and understanding of the business.” Although the industry is seeing some massive changes right now, Gerald believes the role CHOA plays is instrumental for future success. “CHOA is knowledge, communication, education – helping people understand what the industry is all about. To be able to speak articulately and intelligently about the successes and how we are well positioned for the future.”










CURTAILMENT - A TACTIC NOT A STRATEGY By: Caralyn Bennett, EVP & Chief Strategy Officer, GLJ Petroleum Consultants Ltd. This article is based on a presentation made at a CHOA event at the Calgary Petroleum Club on October 18, 2019. The views expressed in the article are the author’s own and are not to be construed as CHOA’s or GLJ’s opinions on this subject.

On December 2, 2018, the Alberta provincial government announced legislation to temporarily curtail oil production in Alberta effective January 1, 2019. The announcement was met with wide-ranging opinions on the need for and efficacy of the intervention. Curtailment has, not surprisingly, remained a topic for debate and discussion throughout 2019. Looking back on the year, we can now draw some conclusions on benefits, costs, winners and losers. Before we get to that, let’s recap the lead-up to the announcement, unintended con-

sequences and the industry’s er at about 10-15 USD/barrel. response. During this period, Alberta’s oil How did we get here? production growth outpaced The trigger the addition of pipeline egress and US oil production more The chart below neatly depicts than doubled. By 2018, Alberthe direct trigger for the legis- ta’s production had exceeded lation, explicitly the blown-out pipeline egress. differentials on Canadian oil in October and November 2018. This resulted in increased crude by rail shipments and, Over the previous five years, when combined with a US Midthe price difference between west refinery outage in the fall, West Texas Intermediate (WTI) Albertan oil supply was backed and Western Canadian Select up within our borders. This (WCS), otherwise known as the backup lead to a WTI-WCS difWTI-WSC differential, has been ferential of 45 USD/bbl in Noin the range of 15-20 USD/bar- vember 2018. rel. 10 to 15 years ago, the WTIWCS differential was even low- Importantly, the supply–egress

Fig. 1: Source GLJ Petroleum Consultants

imbalance also affected the Edmonton Mixed Sweet Blend (MSW) prices. Historically, MSW sold at a very tight differential to WTI, but in November 2018, this differential increased to almost 27 USD/barrel. The situation was not sustainable. Many companies were already voluntarily curtailing production given low and, in certain instances, negative wellhead prices. In November 2018, the Canadian Association of Petroleum Producers (CAPP) estimated that, as a result of the differentials, the economy had lost 13 billion dollars in the first ten


months of 2018, including 50 million dollars per day in October. The Alberta government, using a Scotiabank methodology, estimated that the discount on Canadian oil cost the Canadian economy more than 80 million dollars per day. While uncertainty around the estimates of lost revenue remains, it was clear that October-November 2018 prices would cost both the industry and the Alberta government, partners in our resource development, billions of dollars.

Broken Market But how did we get here? In truth, if our markets were functioning properly, curtailment would not have been required and, it’s not just a market access problem. Fig. 2 depicts many challenges faced by the Canadian oil industry over the last decade. These challenges include changes to the Investment Canada Act, our “dirty oil” label, long and uncertain project approval timelines and a lack of investment inflows culminating, most recently, in a disconnect between Ca-



nadian E&P valuations and commodity prices. So, market access alone won’t be the silver bullet we need to right the market. In the words of Alex Pourbaix, CEO of Cenovus, “These are not ordinary circumstances.” It has taken us over a decade to get into this predicament. It will likely take a similar amount of time to get out. The Announcement Premier Notley announced curtailment on December 2, 2018, noting that “Alberta currently produces 190,000 bpd

Fig. 2: Source GLJ Petroleum Consultants

The government’s calculation was provided as:

AB government Q1 2019 estimate 3.890 mbpd raw production 4.310 mbpd supply 4.100 mbpd takeaway capacity 0.215 mbpd excess supply

more than can be shipped using existing pipeline and rail capacity”. Curtailment would apply to operators producing more than 10,000 bpd, the AER would implement curtailment, and it would be temporary. As a result, the government originally set the production curtailment volume at 325,000 bpd, first, to eliminate the supply-egress imbalance and, second, to also address high storage levels late in 2018.

14 THE JOURNAL Curtailment was designed to narrow the differential, reduce price volatility, and augment 2019 government revenue relative to what it would have occurred otherwise. The Order in Council details the purpose of the legislation as follows: • to effect conservation and prevent wasteful operations • to prevent improvident disposition, and • to ensure the economic development in the public interest of the crude bitumen and crude oil resources of Alberta While there were wide-ranging opinions on curtailment, they can be succinctly summed up as “reluctant acceptance of market intervention” with one CEO describing it as “difficult but necessary.”


ment, a change was made to introduce temporary production thresholds as detailed in the Alberta government’s Information Letter 2018-41. It was clear that under the original rules, companies in the process of ramping up production were more substantially impacted than companies with stable production or production that had already been voluntarily curtailed. In other words, companies that had made recent capital investments were being disproportionately curtailed. As a result, for January 2019, operators with production levels 16% or higher relative to their October 2018 production had their allowables adjusted upwards. The government also noted

that industry had expressed concerns that curtailment had the potential to impact safety or cause long term damage to resources. Consequently, the Production Curtailment Issues Panel was established to address industry concerns. Next on December 20, (Information Letter 2018-43) details were provided on the process for consolidation or transfer of allowables between two or more curtailed operators and on December 30 (Information Letter 2018-46), the government updated the curtailment rules effective February 2019 changing the calculation of operator baseline by using the single highest month of production from November 2017 to October 2018. This was to account for recent capital investments, operators with increasing produc-

tion with very few options for curtailment within their portfolio, and to address the possibility of long-term reservoir damage or safety issues. In general, this shifted curtailment from companies with recent increases in production to companies with stable or voluntarily curtailed production and this also had the effect of increasing the number of operators curtailed to 29. Basic Curtailment Calculation The figure below provides the formula for determining curtailment. There are two key components: first, determining the operators’ adjusted baseline (that is, their baseline after the 10,000 bpd exemption) and second, determining the allowable percentage production of the

Evolution One key detail that wasn’t clarified at the time of the announcement was how the production baseline would be established for each operator.

A = operator baseline

The Alberta government’s Information Letter 2018-40 specified that an operator’s baseline was to be based on their six highest individual months of production between November 2017 and October 2018.

C = aggregate adjusted baseline for all operators with an adjusted baseline > zero

As a result, 25 operators were required to curtail a portion of the 8.7% of curtailed production in Alberta.

H = number of days in a month

Unintended consequences were evident from the very beginning. Only one week after the announce-

B = 310,000 bbl monthly exemption E = A – B = adjusted baseline for operator

D = Minister’s amount to achieve the provincial production allocation F = (C-D)/C = percentage of aggregate adjusted baseline that is allowable G = B = 310,000 bbl monthly exemption

I = 31 days Operator curtailment = ((E × F)+G) × H ÷ I Fig. 3:


aggregate adjusted baseline for all operators with an adjusted baseline greater than zero, or, in other words, the aggregate adjusted baseline for all curtailed operators.

Example Calculation

Then, for each operator, that allowable percentage is applied to their adjusted baseline, and the 10,000 bpd exemption is added back to provide their production limit.

B = 310,000 bbl

At the end of January 2019, two more changes were implemented (Information Letter 2019-05).

F = (C-D)/C = 86.1%

The first was to address operators with a high percentage (more than 80%) of freehold production. In this case, in the event that the operator couldn’t meet their contractual obligations, their limit would be adjusted upwards. The second was to address the potential for long term impairment: If an in situ project makes up more than 80% of the total 2019 production forecast for an operator, if the operator has recently started injecting into at least one well within that project, if the operator’s 2019 production forecast is expected to be 125% or more than their 2018 production forecast and lastly, if the operator can demonstrate that compliance would result in long term damage, then their curtailment limit would be adjusted upwards. These changes effectively put a framework around criteria for limit changes for companies with reliance on single projects in growth mode. There were some more chang-



The following figure shows an example for a 50,000 bpd production baseline. Based on the February-March target set by the government, the operator would be curtailed to under 45,000 bpd – a little over 10% below their baseline.

A = 50,000 × 31 = 1,550,000 bbl

E = A – B = 1,240,000 bbl C = 3,460,000 bpd D = 2,980,000 bpd

G = B = 310,000 bbl H = 31 days I = 31 days Operator curtailment = ((E×F)+G) × H ÷ I = ((1,240,000 × .861) + 310,000) × 31 ÷ 31

= 1,377,670 bbl or 44,440 bpd

Fig.4 : es at the end of February (Information Letters 2019-09 and 2019-10), which were largely administrative, providing a new process for consolidation and transfer by extending the deadline for transfers to allow for production true-up at the end of the month. All of this built to the most recent changes (as of the date of the original presentation of this material on October 18, 2019) on August 20 (Information Letter 2019-28) when the newly elected provincial government extended curtailment to the end of 2020 as a result of continued pipeline delays, notably the estimated one year delay of Enbridge’s Line 3 Replacement to H2 2020. At the same time, the government increased the exemption

to 20,000 bpd effective October bbl, and the WTI-WCS differen2019, reducing the number of tial hovered around 10 USD/ companies curtailed to 16. bbl. Unintended Consequences

The result? The economics for rail transportation effectively evaporated with the WTI-WSC differential too narrow to support rail costs of 15-22 USD/ bbl. Consequently, as shown Fig. 6, rail utilization dropped, and storage levels increased, counter to the stated goals of the curtailment legislation.

Unmistakably the adjustments to the curtailment rules between early December 2018 and the end of August 2019 represent the government’s response to early unintended consequences as identified by industry. But, let’s take a look at some additional observable unintended consequences. The chart shows in light blue the Alberta government alUpon implementation of cur- lowables for each month. The tailment in January 2019, Fig. difference between the orange 5 for instance, shows a surpris- and blue lines represent the ingly rapid and dramatic con- curtailed production. traction in the differentials to unexpectedly low levels. As can be seen, the government increased the allowables The WTI-MSW differential between January and February dropped to less than 5 USD/ 2019.



Fig. 5: Source GLJ Petroleum Consultants

Aggregate Single Month Max Nov 2017 – Oct 2018

Storage increase to 37 MMbbl April 2019 then decreasing to 26 MMbbl end August

Fig. 6: Source GLJ Petroleum Consultants


This was done in response to some previously mentioned unintended consequences and the quick unanticipated contraction in the differential, which in turn coincided with the drop in rail utilization. Storage started in late 2018 at 35 MMbbl, increased to 37 MMbbl early in January, and subsequently declined, with curtailment in place, to 28 MMbbl by the end of February.

However, with rail capacity mostly offline in February and March, the storage built to a high of over 37 MMbbl in April. As the government eased curtailment, the differentials have widened a bit further to 12-13 USD/bbl and rail has come back online, decreasing storage to 26 MMbbl at the end of August.



12-13 USD/bbl can support rail. The answer lies in the fact that US gulf coast prices have popped up relative to WTI – sitting about 5-6 USD/bbl higher. Together with the differential, this makes rail economic for at least some operators.

In the chart below, the solid lines are historical prices, and the dotted lines are wellcounts.

A decrease to new oil wells on-stream (a proxy for drilling activity) has been another unintended consequence.

While the 2015 drop in oil wells on-stream was clearly directly related to price, in Alberta the drop was almost certainly exacerbated by the ill-timed

More recently on, August 20, the Conference Board of Canada provided an updated outlook for Alberta, indicating that we would be in recession in 2019, with 0.8% contraction in our economy. This contraction increased eight-fold from their earlier estimate of 0.1% in May 2019. They also noted that construction and drilling would be hit hardest with 10 and 30 percent declines, respectively.

As seen in the following chart, one surprising outcome is that oil sands delineation wells actually increased in 2019. The big players appear to be progressing their long-term plans despite curtailment, which could suggest they believe that curtailment will be short-lived.

One might wonder how the

It is notable that Alberta has been harder hit than Saskatchewan over the past decade.

Fig. 7: Source GLJ Petroleum Consultants royalty review, the increase in corporate taxation, the imposition of the cap on oil sands emissions, the increase in the specified emitters levy, and the carbon tax. As prices rebounded, so have the well-counts; until 2019, where we see a disconnect with price, paralleling the share price disconnect in the publicly traded oil and gas market. Both Alberta and Saskatch-

ewan have seen contraction to lowest levels, but Alberta, again, is worse off, and curtailment is almost certainly a part of this. In July, the Petroleum Services Association of Canada (PSAC) modified their 2019 drilling forecast for Alberta to ~2400 wells, down over 30% from original estimates. Their stated reasons were curtailment and low gas and liquids prices.

It is also interesting that the “Big 7” make up almost 100% of delineation wells; the “Big 7” defined in this context as



Fig. 8: Source GLJ Petroleum Consultants

CNRL, Cenovus, ConocoPhillips, Husky, Imperial, MEG and Suncor.

decline in 2019 since 2002, primarily due to curtailment. Winners and Losers

Junior oil sands operators’ delineation efforts fell off sharply since 2013, coinciding with foreign capital pulling back, sharp capital cost inflation and some disappointing results in Central and West parts of the Athabasca Oil Sands Region. Not surprisingly, one of the curtailments’ biggest effects has been on growth. CNRL is currently the only company with a new project onstream – Kirby North, with first oil in May. All other projects either have uncertain timing or have been delayed, and a number of previously planned greenfield projects have been cancelled. In August 2019, the Alberta Energy Regulator (AER) released the June data for thermal in-situ production. Thermal production will see its first annual

So, who are the winners and losers? From a short-term or tactical perspective, higher prices have had wide-reaching benefits. Oil and gas companies have benefited from higher revenues and cash flow, Albertans have benefited with increased royalties and taxes flowing to government and, potentially, fewer job losses, and Canadians have benefited from increased taxes and equalization payments. By protecting cashflow for the operators, the service companies have also ended up better than they would have otherwise. The potential losers? Certainly, companies with higher levels of integration, including downstream refining businesses – Husky, Imperial and Suncor all

spoke up against curtailment – have given up some of their downstream margins as a result of higher feedstock costs. But did they lose more downstream than what they gained upstream? This is unclear. From a relative perspective, the curtailed companies themselves are arguably losers. Although, curtailment was designed with a small volume decrease, which we now know has been offset by a large price increase. That said, as for the integrated companies, curtailed companies that had already protected themselves with firm service, hedges, storage, etc., likely haven’t seen the same benefit as those who had not. Clearly, as already described, rail companies have seen business pull back in the first half of 2019. One might also expect that the mid-streamers with feeder

lines to the main hubs would have shipped less volume, but the reality is that we don’t know what would have been voluntarily curtailed anyway. Perhaps they aren’t any worse off. Of particular note, oil futures traders took a hit as a result of the announcement., highlighting concerns around diminished investor confidence, a willingness to invest in the face of jurisdictional unpredictability and the idea of government re-distributing market pain as they see fit. As a short-term tactic, the benefits of curtailment might appear to out-way the costs, but is this true from a longer-term strategic perspective? Are all of the winners ultimately actually losers? Have we given up more than we realize? While curtailment has worked to collapse differentials, it has, in fact, removed or severely limited market forces that would enable or promote




Fig. 9: Source GLJ Petroleum Consultants


Quantifying Benefits

Prior to curtailment, the market was in the process of re-balancing naturally. Companies were curtailing voluntarily, arguably shutting in the highest cost production first, and rail was on the rise. No doubt that without curtailment, the differentials would have remained painfully wide for longer. But there would also have been strong incentives for further expansion of rail, more storage additions, and further pipeline optimization.

In an effort to assess winners and losers, GLJ’s database has been used to understand and model the aggregate impacts of curtailment.

With curtailment in place, we sit in a holding pattern. A no-growth and no-investment holding pattern where the government turns the dial up or down, to ensure that differentials are reasonable, rail makes sense and production is cleared from the market. Now, our only way out is new pipeline capacity, and that has and continues to be an uncertain proposition in Canada.

The model parameters were applied to companies with more than 50% of their reserves in Alberta and more than 50% of their reserves in oil. Ultimately, this included 85% of the oil sands mines, 65% of the in-situ oil sands operators and more than 25 conventional corporates, overall, representing 16 of the 29 companies curtailed early in the year. The incremental benefits of curtailment have been quantified based upon “what actually happened” versus “what might have happened.” The “what actually happened” scenario has been modeled based upon the known curtailed oil production limits through to

the end of October 2019, with October production limits used as a proxy for the balance of the year, and the average actual 2019 price received, including data up to mid-August of 2019. In terms of production, this equates to 4.5% curtailment on average for 2019 relative to the pre-curtailment oil production of 3,80,000 bpd recognized by the Alberta government. Two “what might have happened” scenarios have been modeled. The first scenario using the average actual November 2018 prices and the second scenario using the 2019 strip prices determined at November 30, 2018. In both scenarios, production is assumed as equal to the “what actually happened” scenario when modeling the 2019 impact. Notably, the modeling indicates that the


largest benefit is to in situ, with mining second and conventional operations third. In fact, all but one modeled in situ company would have experienced negative wellhead prices for 2019, in the absence of curtailment. The chart above shows the range and volume-weighted average operating netbacks under the three scenarios and to summarize: “What might have happened.” • Average actual November 2018 price scenario: 40% of mining, 90% of in-situ and 20% of conventional had negative operating income • 2019 strip price at November 30, 2018 price scenario: 40% of mining, 40% of in situ and none of the conventional companies had negative operating income “What actually happened.” • All companies exhibit positive operating income except for one in situ company When the results are applied to Alberta provincial production volumes for 2019 as described above, it was estimated that curtailment added between 31 and 49 billion dollars to company revenues, 2.2 to 3.0 billion dollars to provincial royalties and 25 to 40 billion dollars to company operating income. Clearly, a tactical win and we have witnessed companies using this incremental income to pay down debt, increase dividends and undertake share buybacks. Where do we go from here?


cember 2018 peak of 354,000 bpd and, currently, the Alberta government is reviewing bids in an effort to sell 120,000 bpd of rail contracts purchased in November 2018. CNRL, Suncor and Cenovus have all expressed some interest, provided they receive curtailment credits and an ability to utilize the incremental capacity. There are also a number of near-term pipeline optimizations, which could result in over 200,000 bpd of egress added by the end of 2019 or early 2020. These include 50,000 bpd on TC Keystone, 60,000 bpd on Enbridge Express, 40,000 bpd on Enbridge Mainline and 80,000 bpd on Rangeland and, on a somewhat longer timeline, L3R will add 370,000 bpd hopefully by H2 2020. In the medium to longer-term, the most proximal opportunity might be the reversal of the Southern Lights condensate import line at 150,000 bpd, with condensate supply for bitumen blending replaced with growth in Alberta’s liquids-rich resource plays over the next several years. Of course, we also await the go-ahead on both the Trans Mountain and Keystone Expansions adding over 1.4 million bpd of capacity for as early as late 2022. Industry is also focused on a number of innovative technologies to ameliorate egress challenges, including partial upgrading and alternative products and shipping methods, all with the potential to save about 25% of pipeline space per bitumen barrel transported.

As of mid-October, the curtailment burden rests with 16 companies, 90% of which are weighted to in-situ and mining production. We are, however, locked into the pipeline “waiting game” with limited ability for market self-correction. Until the end of 2020, the provincial government will turn the production dial to balance differentials, rail outflows and storage.

The Alberta Innovates Bitumen Beyond Combustion initiative is particularly exciting as a means of identifying, developing and adding value through a diversified customer base (carbon fibre, vanadium, etc.) while at the same time eliminating or substantially reducing downstream emissions associated with bitumen.

As of July, rail had rebounded to 88% of De-

A Tactic Not A Strategy

As a short-term tactic, curtailment has been a success. It is highly likely that operating netbacks would have been decimated and production would have been cut more dramatically in the absence of intervention. Similarly, corporate and government revenues are likely to have been hollowed out, leading to a drastic reduction in cash available for debt repayment and share buybacks on the corporate side and for public spending on priorities such as health care and education on the provincial side. The curtailment action protected Albertans and many companies operating here. On the flip side, the action mitigated the incentive to grow, it played into the hands to industry detractors, and it effectively took pressure off finding the solution to Alberta’s egress problem. A problem exasperated with the August 20, 2019 extension of curtailment through to the end of 2020. To boot, the implementation of curtailment has added another notch to the belt of government unpredictability in Canada, increasing the political risk profile on investment here. As a long-term strategy, would curtailment be considered a success? What if we are still curtailed in 2021? I will let each of you ponder and answer that question. Since the October 18, 2019, presentation, a number of events have impacted curtailment. The Alberta government has issued two new related Information Letters 2019-38 and 2019-42. On November 1, 2019, the government incorporated a Special Production Allowance under the Curtailment Rules wherein companies may increase their production above curtailment orders using incremental rail capacity above baseline rail capacity determined by the Minister. On December 4, 2019, the government exempted conventional wells with a spud date of November 8, 2019, or later from curtailment, opening the door


for oil production growth outside of the oilsands designated areas and formations. The Alberta government has set curtailment for January 2020 at 80,000 bpd in line with December 2019. Separately, two First Nations previously opposed to the Trans Mountain pipeline expansion have dropped their court challenges, and the Trans Mountain CEO, Ian Anderson, has indicated that “expansion project pipe” will be “in the ground before Christmas.” Some good news for the industry. Merry Christmas!






Q&A with the Canadian Heavy Oil Association 1. AFTER A LONG PERIOD OF STABILIZATION, WHAT ARE THE MAIN ACTIONS BEING TAKEN BY MEMBERS TO OPTIMIZE WORKING CAPITAL MANAGEMENT? The Canadian Heavy Oil Association (CHOA) recognizes the ongoing challenges in working capital management. Measures taken by our members to optimize working capital managementinclude both internal and external measures. Internal measuresinclude a reduction in capital spending, reducedbusiness development costs and layoffs, among others. Lean strategies, such as replacement of full-time technical leadership positions with

that of part-time mentor and contract positions, are some of thelevers being pulled to reduce operating costs. Retiring debt through raising capital, divestitureof non-core assets, selling royalties, and stretching out payables are additional methods. Use of operating line increases to enhance working capital flexibility is another. Externally-focused measures include strategic partnerships, acquisitions and divestitures to enable transfer with less up-front cash, deferring certain growth opportunities. Notably, general and administrative (G&A) reductioninitiativeshave resulted in subleases in offices, reduction in office sizes, etc. Though the observed actions of several companies may appear to be frugal, there

are significant internal investments being made in the development of data science skillsets andworkflow automation,along with the aggregation of smaller improvements to increase efficiencies while accessing minimal capital. On the investment side, the number of transactions taking placehas picked up and is on an upward trend. On the services’ cost front, members are revisiting and re-evaluating vendors, master service agreements (MSAs) and other supply chain streams. Other direct efforts to manage cash flow include renegotiating lending terms, litigating in lieu of settling over claims, and accessing government funding for training, business development and technology development.

2. HOW DO THE ACTIONS IMPLEMENTED DIFFER BETWEEN SMALL/ MEDIUM-SIZED AND LARGE-SIZED COMPANIES? Small to medium sized companies: In the small to medium-sized company segment, the focus is more internal - companies are leveraging office vacancies in Calgary and are generally implementing reductions in salaries, and sometimes offsetting these reductions by providing non-cash benefits such as flexhours and working from home programs. Additionally, reducing the workweek, and restructuring roles from full-time employment


to part-time consultancy reflects responsiveness to the market shifts. The juniors have had a tough time through this downturn. Reporting issuers have dropped from just over 300 companies in 2012 to less than 150 companies in 2019; the majority of that shift is in the juniors. Several companies have been unable to raise money and are holding onto cash reserves as the cost of borrowing operating capital is high. This translates into reduced capital spending, service and consulting companies offering discounts, providing additional services for free to retain customers, and acceptance of detrimental MSA amendments. In some cases, smaller companies are seeking capital from their network all the way up to expensive mezzanine financing, to fund highly selective development. Other creative examples include using the perception of a share price discount to raise equity, untethered to short-term market drivers.


buybacks to support share price are some of the strategies by this segment. Investing in technology, innovation and data science are common here as well, and in CHOA’s opinion these investments are pivotal to future growth and sustainability.

uncertainty which drives project costs upwards. Project proponents have limited control over the timeline for environmental and regulatory approvals, resulting in higher risk to investors and directly impacting the cost of capital and access to capital.

Leveraging economies of scale, large companies are amending terms of MSAs to extend payment terms. This advantage of size, along with supplier discounts, have aided their efforts to actively reduce drilling, completion and facilities’ costs.

The inability to access growing global demand and sell products at global prices is causing a great loss of revenue to Canadian oil and gas industry as well as to the public. Taxes in Canada are high relative to competing jurisdictions, and tariffs on raw materials as a result of foreign policy actions result in a decreased gross margin. Political and ideological messages and the misalignment between provinces and federal government on the energy file is also increasing perceived risk for investors.

3. WHAT BARRIERS CONTINUE TO EXIST FOR MEMBERS TO IMPROVING CASH MANAGEMENT? For service companies, large companies extending payment terms unilaterally results in long collection cycles. Returning to historical payment timelines is therefore a challenge, while a significant segment of the service industry is still struggling.

It seems that as activity within Canada signals a reduction in capital programs, the dividends, however, appear to be increasing, which implies that the companies are trying to attract investors with tighter fiscal discipline and better returns.

Limited access to capital is a barrier which is a result of unfavorable perceptions of industry coupled with the majority of the investment money going to the US. Canadian companies are also hurting due to lack of market access which produces local commodity price volatility. With market access solutions expected to be medium to long term, cash flow will continue to be challenged. Transportation by rail and the curtailment imposed by provincial government have helped ease off some price pressure but these are not long-term solutions.

Opportunistic acquisition of assets and companies and use of cash flow to undertake share

Regulatory approvals for large projects have historically been taking too long, and thus increase

Large sized companies: With large-sized companies, the actions taken to manage working capital have a wider spectrum. Though G&A cuts are obvious, large corporations tend to retain a minimum headcount across key functions.

4. ANY OTHER PERSPECTIVES OR EXPERIENCE TO SHARE? The high cost of capital and risk aversion in light of previously highlighted challenges lead to deferred investment in expansion. As a result of significantly reduced access to capital, almost all development must be funded from cash flow. Private companies are better poised than public in this situation as they can remain longer term focused. Private equity and activist investors are taking greater ownership in the performance of their investments. The public narrative on climate change has morphed significantly over the last decade and there is growing environmental activism and opposition to energy development, particularly fossil fuels. To adapt, a focus on Environmental, Social, and Governance (ESG)


and clean technology must be a priority if we are to survive as an industry; the industry of tomorrow cannot look the same as the industry of the past. Effectively, the junior, intermediate and major oil and gas company “balance” is askew. Many juniors are disappearing, and their assets being bought by majors, which often results in a reduced overall staff. The employees that remain have heavier workloads and more stress. Policies implemented by the provincial and federal government in the last few years have been detrimental to the energy industry, its investors and entrepreneurs. The industry is consequently struggling to retain experience within Canada and attract the talent we need to evolve and remain healthy into the future. The perfect storm we are weathering has been a decade in the making and will take some time to correct. The industry-implemented quick-fixes (cutting staff, applying pressure to suppliers, cutting costs, and divestments) are not sustainable strategies to promote the long-term health of our industry. The real benefits will come from our investments in technology and innovation and our ability to engage the younger generations in delivering the solutions that society requires. Here in Canada, we are endowed with one of the largest energy resources in the world, as well as world class talent – an innovative and skilled workforce. We are a resilient group and we are up for the challenge, an exciting challenge with the potential to make a difference to society on a global scale.







ULIANA ROMANOVA She would eventually fall in

Uliana Romanova’s story is not that of a typical Canadian employed in the energy sector. Hailing from Tatarstan, Russia, she first came to Canada for the Canadian International Petroleum Conference in 1996.

love with the people and the country, working five years in order to immigrate to Canada. After completing a Master of Science degree in Physics and a Ph. D. degree in Chemistry from Russia, then her post-doctoral in Paris, she received a job offer from the University of Calgary to do research in the areas of oil sands in 2001. Prior to her current employer, Baker Hughes, a GE Company (BHGE) Uliana’s first job in the private sector was at Hycal Energy for about 10 years. Starting out as a project engineer completing special studies for operators in the oil sands, Uliana moved up and became a team lead in the engineering group, before working with sales as a technical advisor. Uliana has also worked for a number of other companies, with over 25 years of work experience related to research and technology in heavy oil and oil sands with a focus on reservoir studies in areas such as formation damage and sand control. Volunteer Efforts During her career, Uliana also

became involved in several industry conferences and technical committees. She is currently a member of SPE and CHOA and has served on the Board of Directors of the Petroleum Society of CIM, as a Board Member and the Board Chairman, and was actively involved in the merger of the Petroleum Society of CIM with SPE and establishment of SPE Canada. She is also an author and co-author of over and impressive 50 technical publications. She also is a recipient of the Distinguished Service Award of the Petroleum Society of CIM and the Regional Service Award of SPE Canada in Formation Evaluation. CHOA and The Future Prior to becoming an active member of CHOA, Uliana first served on the organizing committee of Slugging It Out. She also presented as a speaker on the subject of sand control for thermal production operations at CHOA Business Conference and Beer & Chat. Uliana truly believes in sharing knowledge and experience is a key to strengthening the energy industry for both efficiency and developing the technology it uses.

“We’re not going anywhere because oil sands are a major resource.” She says. “We have to continue working on the technology. We really have to educate the public. We need to be more vocal about what we do, and why what we do is important. “ “We’re not really competing against each other,” she continues, “We’re competing against the outside world, so the better we are in terms of technology, at minimizing environmental impact then the better we are as an industry, as Albertans and as a country.” As someone who loves spending time hiking and, in the outdoors, Uliana Romanova believes in the environmental standards that the industry companies are working toward. “We all love nature and we’ll all here…We want our children and grandchildren to have a good life.” And, like many of her industry peers, she would like to see a unified message among “All of us in the Canadian energy industry.” It’s one that many believe we’re just not seeing. At least, not yet.



BAKER HUGHES BRINGS ENTERPRISE AI TO CANADA Baker Hughes is an energy technology company that provides solutions for energy and industrial customers worldwide.

Built on a century of experience and with operations in over 120 countries, our innovative technologies and services are taking energy forward – making it safer, cleaner and more efficient for people and the planet. In Canada, Baker Hughes has more than 1500 employees from BC to Newfoundland. The company is uniquely positioned as an energy technology company, with a diverse portfolio that spans the entire energy value chain. Recently, Baker Hughes Baker Hughes,, and Microsoft Corp. announced an alliance to bring enterprise artificial intelligence (AI) solutions to the energy industry on Microsoft Azure, an industry-leading cloud computing platform. These efforts are underway in Canada now. This alliance will enable customers to streamline the adoption of scalable AI solutions for the energy industry that help promote safety, reliability, and sustainability. It leverages the significant energy technology expertise of Baker Hughes,’s proven AI platform and applications, and the Microsoft Azure cloud computing platform. As a result, energy businesses will have a secure and reliable suite of enterprise-scale AI applications optimized to run on Azure. These solutions are tailored to address challenges across

the entire value chain, from inventory optimization and energy management to predictive maintenance and process and equipment reliability. “The industry is adopting technologies that help manage the challenges and opportunities associated with the energy transition. The AI solutions offered through Baker Hughes and deliver insights that can reduce risk and improve performance for operators as they navigate this transition,” said Lorenzo Simonelli, Chairman and CEO, Baker Hughes. “With a singular offering that can accelerate digital transforma-

tion across the sector, energy businesses can now draw on the power of Microsoft’s cloud,’s leading AI capabilities, and Baker Hughes’s expertise in the energy industry.” “Shell supports the aim of this strategic alliance to improve efficiencies, increase safety, and reduce environmental impact through digital transformation, aligning seamlessly with our goals and ambitions,” said Jay Crotts, Shell Group CIO. “Baker Hughes is one of our long-standing and valued partners in oilfield services and software development, and we use the


platform on Microsoft Azure to accelerate digital transformation across our business, helping to improve overall operations. The new technologies being developed will be critical as we all need to work together to reduce the net carbon footprint of the products and solutions that we put into society.” “We are witnessing a massive market shift as oil and gas businesses undergo enterprise-level digital transformation to improve efficiencies and increase safety, while simultaneously reducing environmental impact,” said Thomas M. Siebel, CEO, “With Microsoft’s global reach and horizontal cloud platform, Baker Hughes’s technology domain expertise, and’s industrial AI capabilities, organizations can rapidly improve core business operations and better serve customers with AI-enabled products and services. This strategic alliance is a complete game-changer for the industry.” The solutions will simplify the process of adopting AI capabilities for energy companies, starting with the shift of data management, storage, and compute onto Azure, through the development and enterprise-wide deployment of domain-specific AI applications built on the BHC3 AI Suite. “For the energy industry, this is a time of significant transformation, and forward-thinking companies are exploring how to leverage technology to make their operations cleaner, safer and more efficient,” said Judson Althoff, EVP, Worldwide Commercial Business, Microsoft. “By bringing together the domain expertise of Baker Hughes and the AI strengths of to run on Microsoft’s Azure cloud platform, customers can achieve new levels of digital transformation while advancing their sustainability commitments.” To learn more, visit





FIREBAG’S JOURNEY TO DIGITAL TWIN: FIREBAG SAGD RESERVOIR SIMULATION Jinze Xu, Jin Wang, Hossein Aghabarati, Amir Zamani, Kathy Cheung Suncor Energy Inc.

Abstract Suncor’s Firebag Project is one of the largest steam-assisted gravity drainage (SAGD) projects in the world. As a powerful tool for decision-making in the field, the Firebag SAGD reservoir simulation platform is successfully developed. This platform shows a promising physical and practical performance, which is based on an in-depth understanding of physics that controls thermal recovery process and meets the need for a practical solution. In this platform, standardized inputs and workflows are developed, and a good agreement with field data is achieved for all Firebag SAGD operating pads with production history. The Firebag SAGD reservoir simulation platform promotes the capacity to address existing Firebag SAGD challenges, capture unique Firebag reservoir features, and support reservoir management and future pad development. Introduction Suncor’s Firebag Project is one of the largest SAGD projects in the world and has a production nameplate of 203,000 bbl/ day. Since 2003, the project has produced over 500 MMbbls of bitumen from the Lower Creta-

ceous McMurray Formation.

reservoir features based on inhouse geological and geophysiThe McMurray Formation in cal (G&G) interpretations, laboFirebag is a structurally un- ratory experiments, field tests, complicated and interbedded and production history. sand and mud package informally divided into three units: A reasonable history match upper, middle, and lower (and (rate, pressure, time-lapse further subdivided into lower seismic and observation wells) McMurray 1, 2, and 3). is achieved for all Firebag pads on production at the well/ The reservoir exploited in Fire- pattern/pad level with seven bag is focused on lower Mc- multi-pad geostatistical models Murray 3 and middle McMurray (Figure 1). (Gray, 2019). A forecast is performed indeGiven the long operating his- pendently for comparison with tory and reservoir complexity, in-house analytical forecast rea Firebag SAGD reservoir sim- sults, which indicates high-levulation platform is required to el agreement. At present, the properly capture SAGD perfor- Firebag SAGD reservoir simmance and support reservoir ulation platform actively supmanagement and future devel- ports Firebag reservoir optiopment. mization and well intervention activities. The overall concept of designing a Firebag SAGD reservoir This platform shows not only simulation platform is to devel- promising performance in the op a comprehensive tool that practical perspective but is translates Firebag subsurface also based on an in-depth undynamics to standardized mod- derstanding of physics. eling and simulation language. From the theoretical perThis tool will then become a spective, the importance of powerful method to integrate convective heat transfer and and minimize many uncertain- condensate movement in the ties (e.g., forecast of new pads), cold reservoir zone is a major computational resources (e.g., improvement in the simulation software licenses), and human of Firebag SAGD performance. efforts (e.g., decision-making). This physical procedure enaWith this goal, the unified, re- bles rapid and lateral steam peatable, and standardized in- chamber growth for heating puts and workflows are devel- the reservoir bitumen, thereby oped to promote unique Firebag enhancing production.

On this basis, the high steam injectivity and “fat steam chamber” are explained. A dynamic interaction between neighboring pads is illustrated based on fluid saturation redistribution with operational changes (e.g., new neighboring pad online). This interaction is frequently accompanied by pressure difference, convective heat transfer flux, and fluid mobility. The Firebag SAGD reservoir simulation platform enables the timely optimization in steam chamber pressure operation between neighboring pads to yield optimal steam–oil ratio (SOR) and aid in effective steam management. Another achievement of this work is the development of practical models with sufficient details of geology and heat transfer physics to overcome limitations in existing computational resources (software and hardware) and provide reasonable solutions in a timely manner. During the history matching process, a reasonable balance between simulation model size and run time is achieved. The importance of heat convection and conduction is utilized to obtain an optimum grid size




Figure 1 Schematic graph of Firebag SAGD reservoir simulation platform

without compromising accura- which are consistent with field (1) Computational speed cy. data. Computational limitation challenges the applicability of the The existing computational Technical work in the Firebag reservoir simulation platform capacity of software and hard- field is further assisted based in real field work when develware limits the running speed on the developed platform to oping models for fields, such as of a single full-field model for support reservoir management Firebag. the entire Firebag project, but and development. unified and standardized workThe first goal of this platform flows and inputs provide a re- The main foci of this work are is to develop an optimum modmarkable basis for future work. to minimize the customization eling and simulation practice Results and Discussions of every pad and obtain a solu- that can guide field production. Reservoir simulation is a pow- tion that honors the majority of Therefore, efforts are focused erful tool to visualize and un- Firebag pad performance. on model acceleration. derstand SAGD performance (Xu et al., 2017). This strategy, based on the The proper setup in model size, overall understanding of the numerical tuning, rock type, The Firebag SAGD reservoir Firebag geology is the main and relative permeability is simulation platform supports goal of platform development. required to achieve reasonable reservoir management and derun time. velopment in an easier, faster, Platform Development and improved manner. G&G, Developing a practical and (2) Unified inputs and workreservoir engineering, and pro- physical SAGD reservoir sim- flows duction engineering are first ulation platform is challenging Disunity in inputs and workbridged based on standardized for a large field, such as Fire- flows makes it challenging to workflows and inputs. bag. conduct new well forecasts and develop new technologies. The platform performance is The solution can overcome the then validated by the results, following challenges: Achieving good physical match

under unified inputs and workflows is a challenge while developing this platform, especially when the geological model allows too many customizations in existing operating pads. (3) Honoring physics of reservoir fluids A good simulation platform should be developed based on an in-depth understanding of physics. Using the correct physics principles to bring reservoir fluids (e.g., fluid transport, heat conduction, and convection) into the platform is also a priority in this project. Notably, this process must involve engineering assessments to ensure that the model is practical. Hence, the simulation platform should focus on factors that



affect the performance of base into simulation language (e.g., SAGD and infill wells. PVT). (4) Field application The developed platform should have added value to guiding field work. The application of this platform to specific production problems determines its stability and practicability.

Relevant field tests are also conducted to obtain relative permeability curves that could determine the physics of heat transfer and fluid distribution.

The production history is transferred to proper well conThe key to dealing with predict- straints using in-house tools to able challenges is the innova- ensure that wells are not over tion, normalization, and stand- constrained. ardization of the workflow. History matching is performed Workflow development is initi- based on the global modificaated from a multi-pad geosta- tion of inputs with the largest tistical model with typical Fire- uncertainties and validated bag features after an in-depth against real field data, includreview and selection. ing rate, pressure, time-lapse seismic, and observation wells. Figure 2 shows that the in- Numerical optimization of inhouse geostatistical model is puts (e.g., continuous property first used to determine struc- distribution) is performed to tures, zones, and petrophysical accelerate the simulation. parameters. The laboratory test results are then transformed From this starting point, the

process enables us to obtain gravity and viscous and capilthe Firebag-featured inputs lary forces controlling the reand workflows for application covery process. to other SAGD pads. Based on this improvement, Then, the same workflows and the injectivity and productivity inputs that use Firebag fea- among different pads can be tures are repeated in all subse- further understood, and a dyquent multi-pad models, there- namic pad interaction and pad/ by obtaining reasonable history formation interaction of base match and forecast. and infill wells can also be calThus, the entire Firebag SAGD culated and monitored by using reservoir platform is developed this platform. by using seven history-matched geostatistical models, which (2) This platform can physically are combined to mimic the res- mimic the proper growth rate ervoir dynamics of all the Fire- of the steam chamber. bag SAGD pads in production. This improvement is based on The following improvements a good understanding of verare noted on the physical un- tical and horizontal fluid flow derstanding of Firebag SAGD and heat transfer based on labproduction in this platform: oratory data, observation well data, and field tests. (1) This platform can use heat convection and condensate (3) Reservoir engineering feamovement in the cold reservoir tures in different formations to control the balance between are used because these engi-

Figure 2 Development workflow of Firebag SAGD reservoir simulation platform




Figure 3 (a) comparison of injected steam, produced water and produced oil between history and reservoir simulation; (b) comparison between average reservoir pressure from simulation and historical steam chamber pressure

neering inputs can present the physical properties (e.g., heat loss) of geological formations. Platform Performance Standardized workflows and inputs generate promising history-matched geostatistical models in this platform. Key validations against real field data are presented as follows: (1) Rate and Pressure Rate and pressure are the key injection and production data to be monitored. These data are the first matching targets in thermal reservoir simulation because they ensure that proper heat and material balance are obtained in the model. The steam injection rate, water production rate, oil production rate, and steam chamber pressure can be matched at the well/

pattern/pad level. Figure 3 shows a pattern–level match of rate and pressure based on multi-pad geostatistical models. A good match is obtained in rate and pressure, thereby providing the necessary confidence in the material and energy balance and the strong support and accurate restarting point for the forecast. (2) Time-lapse seismic Time-lapse seismic effectively monitors the steam chamber growth and provides a 3D image of the recovery process at different snapshots of time. In this platform, the steam chamber thickness can be matched at different years. Figure 4 indicates a high-level agreement between time-lapse seismic and reservoir simulation results at the pattern level.

This agreement with time-lapse seismic results yields high confidence in steam chamber thickness in the reservoir simulation and reduces the uncertainty in the forecast of new wells (e.g., sidetrack). (3) Observation well Observation wells provide real-time measurement at a certain location. This information can show the interaction between SAGD production and formation response. Figure 5 compares the temperature between the observation well and reservoir simulation, thereby indicating consistency. The difference in results is due to the averaging effect of the simulation grid size. A match with observation well data shows the satisfactory performance of this platform.



Figure 4 Comparison of steam chamber thickness between reservoir simulation and time-lapse seismic

Figure 5 Comparison of temperature file between real data from an observation well and reservoir simulation




Platform Application This platform can provide the technical support for reservoir management and development. These field application cases are presented as follows: (1) Production forecast A forecast is performed independently based on the platform and compared with the in-house analytical tool. This analytical tool can provide performance forecasts (Miura and Wang, 2012; Adesimi and Wang, 2013). Figure 6 shows the comparison of independent production forecasts between the results of simulation platform and analytical tool, thereby indicating high-level agreement. (2) Well diagnostic and optimization This platform supports the well diagnostics for operations.

Figure 6 Independent production forecasts from reservoir simulation and in-house analytical tool

For example, one of the Firebag producers is hot, and engineers can utilize the simulation platform to obtain technical assistance. Figure 7 illustrates that the temperature distribution along the wellbore is consistent with the temperature fall-off test based on the history-matched geostatistical model. (3) Workover optimization This platform supports workover evaluations, such as sidetrack opportunities and installation of flow control devices (FCDs) and can estimate pressure, temperature condition, and oil recovery state. The effect of new wells on neighboring wells/pads can also be evaluated based on the current platform. Moreover, this platform can support other field works, such as late-life optimization and brownfield growth deve-

Figure 7 Comparison between temperature along the wellbore and the temperate fall-off test: (a) reservoir simulation; (b) temperature fall-off test



lopments, disposal and make up of water demand, and asset retirement plans. Overall, the Firebag SAGD reservoir simulation platform demonstrates the technical capabilities of applying reservoir simulation in a practical sense to optimize reservoirs, quantify uncertainties, and make decisions. The Firebag SAGD reservoir simulation Conclusions The Firebag SAGD reservoir simulation platform is successfully developed. This platform shows a promising physical and practical performance as follows: (1) This platform uses standardized and unified workflows and inputs to visualize and simulate Firebag reservoir perfor-

mance. (2) This platform uses the right physics of reservoir fluids based on an in-depth understanding of heat and mass transfer. (3) This platform obtains results that agree with field data for all Firebag SAGD operating pads with production history. (4) This platform helps in decision-making and provides strong technical support in reservoir management and development in Firebag. Acknowledgements The authors gratefully acknowledge Suncor Energy Inc. for permission to write and present this paper.

[1] Gray, H. A. (2019). Depositional Architecture of the middle McMurray Formation: Suncor Firebag SAGD Asset. CSEG GeoConvention. [2] Xu, J., Chen, Z., Dong, X., & Zhou, W. (2017). Effects of lean zones on steam-assisted gravity drainage performance. Energies, 10(4), 471. [3] Miura, K., & Wang, J. (2012). An analytical model to predict cumulative steam/ oil ratio (CSOR) in thermal-recovery SAGD process. Journal of Canadian Petroleum Technology, 51(04), 268-275. [4] Adesimi, Y., & Wang, J. (2013). An integrated practical approach to forecast multi-well SAGD production using analog, analytical, and numerical modeling techniques. In SPE Heavy Oil Conference-Canada. Society of Petroleum Engineers.


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chine learning IP, and being a supplier of data and IP to our clients. We don’t just embrace and apply new technologies to our work; we help clients with new technology ideas from concept to implementation, ensuring we’re all moving forward together.


Photo courtesy of GLJ Petroleum Consultants A collaborative approach on a global scale: it’s straightforward, and it’s something GLJ Petroleum Consultants (GLJ) has been refining for nearly 50 years. With local and international experience in over 25 countries, GLJ has become a highly respected and well recognized energy consulting firm. Our experience spans heavy oil, shale plays, tight oil and gas, conventional oil and gas, and renewables. We’ve taken what we’ve learned and applied those insights across borders to support clients and provide the type of value that helps companies succeed.

Our path to becoming leaders in heavy oil began in the 1980s when we undertook our first oil sands mining evaluation. We’ve since handled evaluations including the Athabasca Oil Sands Project, Fort Hills, Joslyn, Syncrude, Audet, Horizon, Suncor Mine, and Voyageur South. Plus, we’ve evaluated hundreds of in situ oil sands assets, strengthening our experience and knowledge base to provide evaluations our clients can count on.

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Every project we do is unique and requires a collaborative approach to provide real value. We work in sync both as a team of geologists, engineers, data scientists and business advisors, and with our clients to deliver reliable and comprehensive business solutions. At GLJ, we work with new, innovative technology to bring pioneering ideas to the forefront of the industry. This currently includes automation of reserves workflows with our proprietary benchmark forecasting tools, technology development road mapping, clean technology projects including geothermal, data science optimization projects through our acquisition of, our partner, Verdazo’s ma-

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CHOA BOARD 2019-2020 OF DIRECTORS President Caralyn Bennett GLJ Petroleum Consultants

Secretary Gordon Holden Surmont Energy Ltd.

Vice-President Heath Williamson CutBlack Ventures

Director Louisa DeCarlo Danrich Resources Corp.

Treasurer Hansine Ullberg Kostelecky RGL Reservoir Management Ltd.

Director Kudjo Fiakpui Alberta Energy Regulator

Director Carmen Lee Husky Energy Director Keith Schilling Baker Hughes Director Allan To Suncor Energy Past President Scott Rempel Wood

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DISCLAIMER: The purpose of the Journal of the CHOA is to publicize the association’s activities and provide an appropriate technical, educational, and social forum for those employed in or assocated with the heavy oil and oilsands industries. Association publications shall contain no judgmental remarks or opinions as to the technical competence, personal character or motivations of any individual, company or group. Further, technical remarks, opinions and conclusions expressedin articles published in the Journal of the CHOA are those of the author and are not officially endorsed by the CHOA unless otherwise noted. Material contained in the Journal of the CHOA is intended for informational use only.