Canadian Oil Research Articles

Canadian Oil Sands Output Cut 1 Million B/D What Could Go Wrong?

When Matt Fox, chief operating officer for ConocoPhillips, was asked about how the company is managing its 100,000 B/D reduction at its Surmont project, the response was reassuring. “We’re not doing anything that’s going to take any risk either from a reservoir or wells or facilities perspective. That’s why … in Surmont, we’re going down to a minimum rate, so that we can still provide enough heat and temperature to the steam chambers to keep them intact,” Fox said during a recent call with stock analysts. To be clear, he is not saying there is no risk. ConocoPhillips and others are using various methods to turn down production that maintain the heat and pressure they spent years creating in reservoirs where pairs of wells are used to inject steam to heat bitumen. Gravity then drains the melted bitumen down to the production well in a process known as steam-assisted gravity drainage (SAGD). While what they and other companies in the oil sands are doing is commonly described as shutting in wells, they are actually slowing the production from those wells. Some use reduced steam injections in a well pair, alternate cyclic injection among wells, or injections of gas to maintain the pressure. “It is a good test case,” said Scott Norlin, a research associate at Wood Mackenzie. The geologist who used to work in the oil sands said shutting in wells is not a good description of how they are cutting production. “It is almost like cooking a turkey for Thanksgiving,” and dinner is delayed, so “you turn the temperature down. You’re not throwing it back in the freezer,” he said. Future productivity in wells that have been turned down requires maintaining the temperature and pressure at levels high enough to preserve the steam chamber - the area above the injection where the water vapor thins peanut-butter-thick bitumen so it can flow. Keeping it hot enough to maintain the steam is critical because if it is allowed to condense into liquid form, it will cause a pressure drop which can open the door for serious trouble. The minimum safe injection level will vary based on factors ranging from a water layer next to the steam chamber to the age of the well. Years of steam injections warm the rock around the productive zone, slowing cooling if the injections are stopped or reduced. If there is a water zone in contact with the production zone, too little steam may allow an influx of water, which would quench the steam chamber. “If we cut the steam rate, but keep it high enough to supply the heat loss, and thus maintain the steam temperature (which means pressure), the production rate will go down, but the steam chamber will continue to exist without resaturation,” said S.M. Farouq Ali, a distinguished professor at the University of Houston Cullen College of Engineering.

Disclosure Regulation & Competition from MNCs: Evidence from Canadian Oil Investment

What is the role of the information environment in foreign investment? Do foreign multinationals gain from host-country transparency regulation? This paper explores the informational aspects of liability of foreignness, taking advantage of a natural experiment in the petroleum industry. Canadian securities regulations since 2004 mandate that oil and gas companies include the estimated size and value of underground reserves in their financial reporting. Using gas and oil field acquisition data, the paper examines whether this change affects the asset valuations of reserve acquirers, and whether the valuation effect is different between foreign and domestic firms. Analysis of 2299 oil reserve deals finds that greater transparency has a positive effect on valuation, and the effect is stronger for domestic investment than for FDI, suggesting that domestic firms gained in competition with foreign MNCs for supply sources. The paper draws on economic theories of adverse selection and knowledge perspectives on economic geography to explain its findings.

Evaluating long-term greenhouse gas mitigation opportunities through carbon capture, utilization, and storage in the oil sands

Carbon capture, utilization, and storage (CCUS) has been identified as the only option for substantially reducing greenhouse gas (GHG) emissions from fossil fuel-based processes. There has been limited research into the long-term GHG reduction potential of integrating CCUS into unconventional oil extraction processes. We developed a CCUS-oil sands market penetration model and integrated it with a bottom-up energy model (LEAP-Canada) to conduct a cost-benefit case study for the Canadian oil sands. Scenarios were developed considering currently available CCUS technologies and were investigated under different carbon pricing policies. Cumulative GHG emission mitigation potential from the CCUS applications ranged from 3 to 232 million tonnes (Mt) with marginal costs of $-28–42/tCO2e. Carbon pricing led to an average 3% increase in 2050 market shares of the technologies, resulting in additional GHG abatement of 4.9% (172 Mt). CCUS was found to be the costliest GHG emission mitigation option compared to increased integration of cogeneration and energy efficiency measures. The maximum cumulative oil sands GHG emission mitigation achieved in this study was 7%. This research ultimately provides insights into applications of CCUS technologies into the oil sands industry that might be useful to industry planners and policymakers and support the sustainable development of oil sands resources.

Greenhouse gas emission abatement potential and associated costs of integrating renewable and low carbon energy technologies into the Canadian oil sands

The purpose of this research is to evaluate the greenhouse gas reduction potential and associated costs of integrating renewable energy technologies into Canada’s oil sands . There is very limited analysis in the literature focused on the integration of renewable technology options in oil sands processes. This research addresses the gap by developing a novel framework that applies market penetration and bottom-up energy modeling techniques. A total of 27 long-term scenarios across oil sands extraction, upgrading, and electricity generation were investigated. The results show that up to 84 million tonnes of greenhouse gas emissions abatement (2.3% of oil sands GHG emissions) at a marginal greenhouse gas abatement cost of $1.3/tCO2e is available under a $30/tonne carbon incentive. Scenarios with no carbon incentive resulted in 69 million tonnes less greenhouse gas emissions abatement and a marginal greenhouse gas abatement cost increase of $36/tCO2e. Nuclear-based scenarios mitigated the largest amount of greenhouse gases and had the lowest marginal abatement costs. Geothermal energy, bioenergy, and hydropower were cost effective in certain scenarios but had limited greenhouse gas emission reduction potential. Wind and solar technologies failed to displace existing processes in the scenarios considered. The results from this study may be of value to government policy makers and industry representatives aiming to reduce greenhouse gases.

Statistically enhanced model of oil sands operations: Well-to-wheel comparison of in situ oil sands pathways

Abstract Although the life cycle greenhouse gas (GHG) emissions associated with Canadian oil sands have been investigated in recent years, questions remain regarding the source and impact of variability in emissions in this industry over time. This study combines publicly-available data from the fifteen largest operating in situ extraction projects, i.e., cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) with a statistically-enhanced life cycle model to investigate variability in well-to-wheel (WTW) GHG emissions. We estimate that the WTW GHG emissions from CSS-derived gasoline range from 99 to 114 g CO2eq/MJ (80% confidence interval), 6–22% higher than the RFS2 baseline. The corresponding range for SAGD-derived gasoline is 98–133 g CO2eq/MJ, 5–42% higher than the RFS2 baseline. SAGD-derived gasoline has more variability as some operators “upgrade” their crudes, emitting GHGs, whereas no CSS operator employs upgrading. Without upgrading, the 90th percentile for SAGD emissions would be 114 g CO2eq/MJ. Upstream variability in GHG emissions drives the positively skewed WTW GHG distributions. This demonstrates the importance of understanding the nature and magnitude of variability and uncertainty in decision making.

From dirty oil to ethical oil: Petroturfing and the cultural politics of Canadian oil after social media1

This article examines print and screen media produced and circulated by groups and organizations that promote Canadian oil from self-described positions of distance from the oil and gas industry. Offering the term ‘petroturfing’ to describe their collective efforts, I argue that the media produced by these groups and organizations advance their aims to consciously shape our collective energy imaginaries by mirroring the new media strategies and structures of progressive environmental non-governmental organizations. I ultimately show how petroturfing is a ‘permanent campaign’ for Canadian oil that obscures the fundamentally uneven distribution of social and ecological costs and benefits of fossil fuel extraction, foreclosing the possibility of imagining and, in turn, working towards a future beyond the dominant fossil fuel energy regime.

Assessing the public interest in environmental assessment: lessons from cost-benefit analysis of an energy megaproject

ABSTRACT The potential contribution of cost-benefit analysis to environmental assessment is assessed through a case study of a proposed Canadian oil project and a comparison of results with those of the method of economic impact analysis. While the latter concludes that the project would generate substantial economic benefits, the cost-benefit analysis concludes that the project would be a net loss to society and that new oil mining is uneconomic. The case study demonstrates that economic impact analysis can help inform decision-makers of projects’ economic impacts, but the cost-benefit analysis should be used to help inform decision-makers with respect to the contribution of projects to the public interest. It is time to move beyond relying solely on economic impact analysis to measure project benefits in environmental assessment decision-making.

Hard Times in Canadian Oil Could Be Useful Experience

Combine a pandemic, plunging oil demand and prices, and a deep recession, and then consider how it may change things. It is not a question Steve MacDonald can answer, but the chief executive officer for Emissions Reduction Alberta (ERA) said it can be a useful way to get people to consider how things can change in un expected ways. “If you said to someone 4 months ago that oil could go to negative prices, they would say, it’s not going to happen. The range of what could happen is much wider now,” he said. A recent decision by the $1-trillion Norwegian Wealth Fund to exclude four major oil sands companies saying they have “unacceptably high greenhouse emissions” shows the need for change. The headlines in Canada have been harsh - the rising death toll from COVID-19, oil prices flirting with zero, job cuts, and the slow and unpredictable timeline to normal life. “Everything you’re hearing is true. It’s bad,” said Darcy Spady, but the 2018 SPE president is quick to add, “I see a ray of sunshine.” There is a connection between the bright and the dark sides, and it is forcing leaders from both inside and outside the industry to take a hard look at what works and what does not. “The pandemic has merely accelerated the disruption that was already occurring in Canada’s oil and gas sector,” wrote Kevin Krausert, the president and chief executive officer of Beaver Drilling, in an essay in a national newspaper, The Globe and Mail. The essay addressed a long-term future in which the industry undergoes fundamental changes, ranging from research into ways to make hydrogen fuel from gas to drillers digging geothermal wells to provide renewable energy. But at the moment, it is difficult to get the attention of decision makers about the future. “It is hard to focus on anything but the here and now. Where the next dollar is coming from rather than from 3-10 years from now,” said Mark Scholz, president of the Canadian Association of Drilling Contractors. Staying Alive The dramatic drop in oil demand and prices can kill jobs, companies, and ideas. MacDonald sees that threat firsthand. “Liquidity is an issue for everybody, cash flow has been a challenge, the ability to secure investors,” are all issues now affecting those trying to scale up promising ideas. Soon after the economic impact of the sweeping limits that were imposed to slow the spread of COVID-19 became apparent, Emissions Reduction Alberta (ERA) changed its policy to allow increases in progress payments to companies during this period when cash is hard to come by and when some lenders are delaying the release of loan funds, MacDonald said. By reducing the amount of money held back from progress payments, ERA expects to provide 74 companies with $10 million more in cash in the near term. The payments may help client companies pay some bills at a time when they are struggling to line up funding and customers for the large-scale tests needed to prove ideas that worked on a smaller scale.

The Great Shale Shut-In Uncharted Territory for Technical Experts

Facing crippling crude prices and a historic supply overhang, the once-booming US shale sector is for the first time being forced to shut in thousands of wells across its most prolific tight-oil basins. Accurate production data lag by months in the US, but analysts are reporting onshore shut-in for early May to be somewhere between 100,000 to 400,000 B/D. The largest cuts announced so far come from ConocoPhillips which said in addition to its Canadian oil sands projects that it is shutting in nearly the all of its US onshore position - some 2,400 wells, representing about 165,000 B/D. A projection from commodity researchers at JP Morgan Chase suggests as others follow suit these curtailments may reach 1.5 million B/D by June. The business driver behind the so-far uncoordinated effort is crystal clear. Much less so is how the development will play out when prices bounce back up and the wells are turned back on. That part is a subsurface mystery. A new report by Wood Mackenzie published in April summarizes several factors shale producers are dealing with as they undertake painful but necessary shut-in campaigns. The chief risk listed for subsurface considerations was reservoir damage caused by a loss of relative permeability. “Routine short-term shut ins - days to weeks - for maintenance or ‘frac hit’ avoidance seem to cause few reservoir problems,” the report reads. “But wide-spread shut in of tight-oil horizontal wells is rare, so the long-term reservoir response is uncertain.” As the situation unfolds, many in the petroleum engineering community have taken to social media and online SPE forums to ask practical questions about how best to shut in wells, which ones to shut in, and how to restart them again. Some of the answers hinge on how long the shut-ins are meant to last; 2 months or 6 months could make a big difference. “I don’t think anyone really knows for sure what will happen,” said Eric Gagen, who has spent more than a decade restoring shut-in wells offshore and in shale plays. The petroleum engineer served as a technical manager at a coiled-tubing company until industrywide staff reductions began this month. He said long-term shut-ins on the order of several months could introduce a range of issues that span surface equipment operations to “unexpected” downhole chemical reactions. At a minimum, Gagen said operators shutting in for months should expect to see significantly higher water cuts upon restart. In most tight-rock reservoirs, especially those that are oil-wet, water becomes more mobilized than oil over time “and shut-in wells have a tendency to produce even more water as they are put back on production.” Undulating wellbores - a common feature of horizontal wells - may exacerbate this issue. In the worst of outcomes, a water-loaded well produces such an excess of water that remediation efforts stop making economic sense. At that point, the well is a candidate for a plug-and-abandonment operation.

Performance of Canadian banks and oil price movements

We employ dynamic panel data models to examine the performance (profitability and asset quality) of a large sample of Canadian banks from 1996Q1 to 2018Q2. Profits, measured as return on assets (ROA), depend on bank factors (capital adequacy, loan loss provisions (LLP) and non-interest income), the slope of the yield curve, and several oil price measures. Our findings suggest that the persistence of profits is estimated to be around 0.40 and the direct impact of oil prices tends to be positive on profits. When oil interacts with non-interest income, there is a strong positive relationship. This can be interpreted as oil price increases leading to more banking transactions (derivatives, fees) and then higher profits. Our evidence also suggests that positive oil price changes increase the asset quality of Canadian banks by reducing the ratio of LLP.

Effects of Hydrocarbons on Wind Waves in a Mine Pit Lake

The extraction and upgrading of bitumen to crude oil from the Canadian oil sands has produced large quantities of byproducts such as fluid fine tailings (FFT) and oil sands process affected water (OSPW). One reclamation strategy for these byproducts is to backfill a mined-out pit with FFT and cap it with a mix of OSPW and non-process affected water to form a pit lake. We investigated the effects of hydrocarbons, residual bitumen, on the generation and growth of wind waves, both in the laboratory and in a pit lake. In the laboratory, we compared the wind wave characteristics in the presence and absence of a hydrocarbon film. We showed that the hydrocarbon film dampens high frequency waves, resulting in a slower growing wave field dominated by lower frequency waves. These results were consistent with our field observations. Thus, it appears that the presence of a hydrocarbon film on a pit lake leads to a wind wave field dominated by longer wavelength waves that take more time to develop and grow at a slower rate. This is important since wind wave-driven mixing, in tandem with biogeochemical processes, governs water quality in mine pit lakes. Thus, this work improves understanding of the physical processes that effect water quality in mine pit lakes and enhances the ability of mine managers to conduct pit lake reclamation.

Efficiency Measurement of Canadian Oil and Gas Companies

In this study, we perform an efficiency analysis of Canadian oil and gas firms. Using data envelopment analysis, technical, managerial and scale scores from ten samples built from 110 oil and gas companies, listed in Canadian stock exchanges, are computed for the years 2012, 2013, 2014, and 2015. Our analysis, supported by appropriate statistical tests, confirms that the Canadian oil and gas industry exhibited predominantly low overall technical efficiency levels both for each of the years and overall for the four years. We have observed that the main source of inefficiencies was the management of operations. In addition, we have seen consistently that across the samples, a statistically significant relationship exists between the efficiency scores and the size of the companies. Finally, we have observed the existence of a relationship between the efficiency scores and the type of producer (pure oil vs. oil and gas), but we could not reach conclusions on the best performer that was consistent across the samples.

Oil sands, pipelines and fracking: Citizen acceptance of unconventional fossil fuel development and infrastructure in Canada

As unconventional fossil fuel production expands in much of the world, so does controversy, and in many cases, public opposition. This study explores citizen perceptions, support, and opposition for several types of unconventional fossil fuel in the case study of Canada, where such production continues to grow. We use a nationally representative survey of Canadians (n = 1407) to assess citizen acceptance of oil sands development and natural gas development using hydraulic fracturing, as well as related infrastructure (specifically the Northern Gateway, TransMountain, and Energy East pipelines). We compare this acceptance to other forms of energy generation, namely conventional oil, coal, renewables, and nuclear. Across the Canadian sample, oil sands and pipelines tend to have less acceptance than renewables and conventional oil, but more acceptance than nuclear and coal power. Acceptance for unconventional fossil fuel development and infrastructure is consistently higher among respondents in Alberta (the province where most development occurs), where respondents perceive more economic benefits and less environmental and social costs. Within each region, acceptance levels are similar for oil sands and oil sands pipelines, while hydraulic fracturing has significantly lower acceptance within all regions. Regression analyses indicate consistent patterns: opposition to unconventional fossil fuel developments and infrastructure is predicted by higher biospheric-altruistic values and environmental concern, and support is predicted by higher egoistic and traditional values and higher trust in oil and gas companies. Results provide insights to policymakers and stakeholders, including regional differences in acceptance, and how citizens perceive oil sands related projects differently than hydraulic fracturing.

Current status and challenges of the Canadian oil sands industry

Current status and challenges of the Canadian oil sands industry

Quantifying variability in well-to-wheel greenhouse gas emission intensities of transportation fuels derived from Canadian oil sands mining operations

How oil sands bitumen is produced (through mining or in situ methods) and how the crude is processed (either upgraded to synthetic crude oil, SCO, or diluted to produce dilbit) result in a range of crude properties with distinct downstream emissions. Previous life cycle studies of the greenhouse gas (GHG) intensities of transportation fuels derived from oil sands bitumen have not accounted for this downstream variability. We quantify, on a project basis as well as across the industry, variability in well-to-wheel (WTW) GHG intensities of transportation fuels from mined oil sands bitumen using detailed upstream, crude transport, and refinery models. Across projects, the mining project producing dilbit has lower median WTW GHG intensity per MJ (low heating value basis) gasoline (median: 96; 80% confidence interval: 93–101 g CO2eq/MJ gasoline) versus SCO projects (median: 108–114; 80% confidence interval across all SCO projects: 106–123 g CO2eq/MJ gasoline) but is strongly influenced by assumptions regarding refinery configuration and allocation to refinery products. Intraproject variability exceeds interproject variability, with 80% confidence intervals for individual projects varying up to 16 g CO2eq/MJ, and is driven in approximately equal proportions by the upstream and refining stages, although their relative contributions vary across projects. Compared to the U.S. EPA baselines, the mining project producing dilbit has a WTW GHG intensities that range from 1% (lower) to 8% (higher) and 2% (lower) to 6% (higher) for gasoline and diesel, respectively (80% confidence intervals). Across mining projects producing SCO, WTW GHG intensities range from 10 to 32% higher and 2–25% higher than the U.S. EPA baselines for gasoline and diesel, respectively. We show how downstream modeling decisions (e.g., allocation of refinery emissions to products such as gasoline) influence WTW GHG intensity distributions, compare mining and in situ bitumen production methods’ GHG intensities, and discuss implications for meeting intensity-based targets.

Chronic Toxicity of Surface Water from a Canadian Oil Sands End Pit Lake to the Freshwater Invertebrates Chironomus dilutus and Ceriodaphnia dubia.

Permanent reclamation of tailings generated by surface mining in the Canadian oil sands may be achieved through the creation of end pit lakes (EPLs) in which tailings are stored in mined-out pits and capped with water. However, these tailings contain high concentrations of dissolved organics, metals, and salts, and thus surface water quality of EPLs is a significant concern. This is the first study to investigate the chronic toxicity of surface water from Base Mine Lake (BML), the Canadian oil sands first large-scale EPL, to aquatic invertebrates that play a vital role in the early development of aquatic ecosystems (Chironomus dilutus and Ceriodaphnia dubia). After exposure of C.dilutus larvae for 23days and C.dubia neonates for 8days, no mortality was observed in any treatment with whole BML surface water. However, the emergence of C.dilutus adults was delayed by nearly 1week, and their survival was significantly reduced (36%) compared with the controls. Reproduction (fecundity) of C.dubia was reduced by 20% after exposure to 2014 BML surface water; however, the effect was not observed after exposure to BML surface water collected a year later in 2015. Despite some adverse effects, the results of this study indicate that BML surface water quality is improving over time and is able to support certain salt-tolerant aquatic organisms. Because salinity within BML will persist for decades without manual intervention, the ecological development of the lake will likely resemble that of a brackish or estuarine ecosystem with reduced diversity.

Microwave-assisted Petroporphyrin Release from Asphaltene Aggregates in Polar Solvents

This work presents an efficient approach for the primary separation of the petroporphyrin component from asphaltene aggregates. The n-pentane asphaltenes separated from the vacuum residue of Canadian oil sands bitumen were used as the feedstock. The release behavior of petroporphyrins from feed asphaltenes in polar solvents with the assistance of microwave irradiation was investigated. UV–vis spectroscopy was utilized to calculate the petroporphyrin release efficiency (PRE). The effects of asphaltene concentrations and solvent properties on the PRE were discussed. Results show that, under the microwave irradiation, asphaltenes could be rapidly separated into soluble and insoluble fractions. The solubles are enriched with vanadyl porphyrins, while the insolubles present only weak absorption of nickel porphyrins at proper asphaltene concentrations. The dispersion force (fd) of solvents has a strong correlation with the PRE. Under the optimized conditions of the methanol/toluene volume ratio of 2:1, the microwave time of 10 min, and the asphaltene concentration of 0.08 g/L, the PRE can reach up to 45%. Compared with the traditional solvent extraction method, the PRE of this new method is improved prominently. The possible mechanism of selective activation of petroporphyrin motivated by the microwave irradiation and the formation of asphaltene vesicles is proposed. This work could provide a more efficient technique to purify petroporphyrins from asphaltenes and could give insight into the interactions between petroporphyrins and asphaltene aggregates.

“Standing Up for Canadian Oil & Gas Families”: Tracing Gender, Family, and Work In the Alberta Petro-economy

Drawing on the social media content of four pro-oil Facebook groups, we argue that these ‘subsidized publics’ play an increasingly critical role in facilitating oil and gas companies’ continued accumulation of fossil capital. We adopt O’Shaughnessy and Krogman’s (2011) analytical framework to reveal material-discursive contradictions obscured from view in the pages of these online groups. Through deploying gendered and familial discourses, these subsidized publics celebrate traditional gender roles, present oil as a ubiquitous and benevolent force, and blur the divide between oil and gas workers on the one hand, and absentee transnational employers on the other. In an era of advanced neoliberal petro-capitalism, these quasi-public entities are masking the inherently unequal power relationship that exists between the two. Moreover, in projecting a working-class ethos, we argue that these familial and gendered discourses create a homogenizing narrative, advancing the false notion of a “classless and horizontally beneficial” industry (Gaventa, 1982, p. 58). Our analysis disrupts neoliberal representations of de-gendered extraction and highlights the extent to which gender remains a key axis within resource communities.

Imperial Standard: Imperial Oil, Exxon, and the Canadian Oil Industry from 1880. Graham D. Taylor

<i>Imperial Standard: Imperial Oil, Exxon, and the Canadian Oil Industry from 1880.</i> Graham D. Taylor

Determination of Carbonyl Functional Groups in Heavy Oil Using Infrared Spectroscopy

In this study, we examined carbonyl functional groups in Canadian oil sand bitumen using Fourier transform infrared spectroscopy (FTIR). FTIR spectra of a bromoform solution of the bitumen fraction...