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U Calgary study finds oil shale most energy intensive upgraded fuel followed by in-situ-produced bitumen from oil sands

A team at the University of Calgary (Canada) has compared the energy intensities and lifecycle GHG emissions of unconventional oils (oil sands and oil shale) alongside shale gas, coal, lignite, wood and conventional oil and gas. In a paper published in the ACS journal Environmental Science & Technology, they report that lignite is the most GHG intensive primary fuel followed by oil shale. Oil shale is the most energy intensive fuel among upgraded primary fossil fuel options followed by in-situ-produced bitumen from oil sands.

Based on future world energy demand projections, they estimate that if growth of unconventional heavy oil production continues unabated, the incremental GHG emissions that results from replacing conventional oil with heavy oil would amount to 4–21 Gt-CO2eq over four decades (2010 by 2050). Taking this further, they estimated that the warming associated with the use of heavy oil amounts to this level of emissions could lead to about 0.002−0.009 °C increase in earth surface temperature, based on mid-21st century carbon-climate response model estimates.

(Oil shale is fine-grained sedimentary rock containing kerogen (a solid mixture of organic chemical compounds) from which shale oil can be produced. This is not the same as crude oil occurring naturally in shales, as in the Bakken. Earlier post.)

Unconventional oil production received a boost recently especially in North and South America with the significant increases in production from oil sands in Canada, tight oil and oil shale in the US, and growth projections of extra heavy oil in Venezuela.

… In addition to environmental implications of unconventional heavy oil production, a fundamental question we ask in this paper is whether it makes sense to extract and use heavy oil resources as a substitute for the dwindling volumes of conventional crude oil, considering fuel extraction energy intensity. Although this question appears to be simple, its answer is not straightforward, yet, answers to the following questions may provide suggestions for policy: What fraction of energy from the resource is lost during the recovery process? How does this relate to the life cycle greenhouse gas (GHG) emissions intensity? How do energy and GHG emissions intensities of oil sands bitumen compare to conventional crude oil and other fuel options? We use bitumen extraction from oil sands as a case study to illustrate the energy intensive nature and climate change impact of recovering unconventional heavy oil.

—Nduagu & Gates

The researchers assessed the energy intensity—the amount of energy amount expended in extracting bitumen divided by the amount of chemical energy contained in the bitumen produced, expressed as percentage—and the net energy return (NER) of 10 major SAGD (steam-assisted gravity drainage) bitumen production projects in Alberta.

SAGD uses injection of large volumes of high pressure, high temperature steam into the reservoir to produce bitumen. In addition to the steam energy requirements, electricity is required for water treatment processes and auxiliary equipment such as downhole pumps, pad auxiliaries, glycol system, evaporators, etc.

They found that if the energy content of bitumen is taken to be 42.8 GJ/m3, the results shows that on average,on average the SAGD oil sands industry is achieving ∼4.1 GJ return per GJ invested, equivalent to ∼25% of bitumen energy lost during SAGD extraction process. In other words, an average NER of 4.1. The upper and lower bounds for the projects studied were a NER of 6.1 (16% of energy lost) and 2.1 (47% of energy lost).

Transforming the bitumen into dilbit (a bitumen-diluent mixture) or synthetic crude oil (SCO) entails additional energy, the amount depending upon the type of upgrading. The team established a NER range of 2.7-7.3 for dilbit from SAGD bitumen (the NER can increase because the natural gas condensates displace 30% of the relatively low NER bitumen), or a low 1.3-2.9 for SCO. However, they noted, further processing of dilbit may likely bring the NER values of refined fuels from both pathways close to each other.

Bitumen mining is a less energy intensive; the researchers estimated that 4−7 GJ/m3 bitumen is expended during bitumen mining—representing 8−16% of energy lost to bitumen mining process. Subsequent bitumen extraction gives a wide range values for NER because the major commercially practiced bitumen recovery methods differ in terms of energy intensities, resulting in different ranges of NERs.

Percentage of harvested energy lost to process considerations (on y-axis) against life cycle fuel GHG emissions intensities (on the x-axis). Credit: ACS, Nduagu & Gates. Click to enlarge.

By comparison, oil shale has NERs (or EROI) of 1.6−2.0 for both in-situ and ex-situ oil shale extraction processes; conventional oil and gas has EROIs of 11−20; unconventional natural gas (e.g., from the Marcellus Shale), the energy extraction losses could be as low as about 2% of the energy extracted. The reported EROI for Marcellus Shale gas is 64−112 with an average of 85.1, according to the Calgary team.

They categorize the primary fuels into three major energy intensity classifications:

  • Class I fuels with 1−5% of its energy lost to the extraction processes, examples are shale gas, wood, coal and lignite.

  • Class II fuels with 5−12% of its energy lost to the extraction processes, which include conventional oil, and natural gas and mined bitumen.

  • Class III fuels, high energy intensive fuels with percentage amount of fuel (energy) expended above 12%. These include mined bitumen (losses 7.3−42%), SAGD bitumen (losses 14−77%) and oil shale (losses 37−63%).

    Mined bitumen falls into both Class II and III fuels because the percentage amount of fuel energy expended during mining and upgrading is between 7.3 and 40%.

The future of the unconventional heavy oil industry, arising from environmental concerns, public perceptions, investment, other fuel options and markets could be either promising or dismal—the former if rapid development and deployment of effective technologies occurs, or the latter if business as usual continues.

If industry and government invests heavily in GHG emissions reduction and water consumption technologies (to be competitive with conventional oil recovery processes), solves social issues (aboriginal issues, perceptions of oil sands), and market access limitations (pipelines), then the outlook for oil sands and its economic and social benefits could be bright. If no significant change in strategy toward reducing oil sands energy and GHG emissions intensity is put in place, in an environment of growing momentum of environmental concerns and alternative fuel developments and increasing market access limitations, the industry may experience limited growth with investment communities migrating away from oil sands toward other fuel enterprises.

—Nduagu & Gates


  • Experience I. Nduagu and Ian D. Gates (2015) “Unconventional Heavy Oil Growth and Global Greenhouse Gas Emissions” Environmental Science & Technology doi: 10.1021/acs.est.5b01913



More good reasons to develop more REs (and NPPs if very high cost and questionable long term safety can be better managed) to replace all fossil and bio fuels ASAP?


I certainly agree; everytime I read about how we have stupidly allowed and continue to allow the hydrocarbon companies to pollute the Planet and how we have lost so much time in developing renewables by believing their lies and propaganda, I turn blind with anger.


Oh My God....and I bet water is wet! And the sky is blue!

What stuns me is that it takes a study to get people to pay attention to the obvious. But even MORE stunning is that the average American is in denial of these facts even when we have them explained to us.


DaveD: Only the kind of people who read this blog will pay attention. As you say, the rest will deny the facts or remain ignorant.


Given that this study was done at the University of Calgary, oil sands country, I'm half expecting them to try to paint this as good news: 'Hey look everybody, our oil sands are way cleaner than that awful american oil shale stuff.'


ai_win...aren't they both as dirty as they come?

However, if you like to have more and more forest fires +++, please continue to use and pollute.


This explains the great interest of some of the SMR start-ups in the Canadian tar patch.  If you have a small reactor producing steam for SAGD, three very good things happen:

  1. You no longer need to pipe in natural gas for process heat (though NGLs for diluent are still desirable)
  2. You slash your cost of process heat (LEU is far cheaper than almost anything else, about 0.2¢/kWh of heat)
  3. Air emissions, especially CO2, drop drastically.

Such bitumen would still hardly be clean, but it would be much cleaner than before and it might make surface mining uneconomic.


What stopped tar sands operators from using this (cleander money making) process for the last 20++ years?

Nuke-heat technology has been around for 50+ years.

Would a significant (progressive) pollution tax help to convince Oilcos to extract oil differently?

Burning that black stuff in ICEVs would still pollute?


Harvey, do you actually remember 30 years ago?  Oil was getting very cheap compared to the OPEC-shock highs, natural gas was plentiful, nobody was concerned about coal very much, climate change was scarcely a political issue, nuclear power was demonized when it wasn't just "too expensive".

All of that has changed, partly or completely.


Oilcos do not change their methods much unless they are forced to do it by public pressure or taxes.

The normal thing to do for Oilcos is the lowest cost approach regardless of the pollution created. The same applies to Oil transportation methods. The lowest cost methods with minimum safety by all means.

In Situ + nuke heat sources has been on their lips for more than 20 years but they will not go ahead much unless Alberta and other governments apply significant carbon or pollution taxes.


Obviously you do NOT remember 30 years ago.

Today the differences are huge:

  • Natural gas has hit prices upwards of $14 per million BTU at the Henry hub (2008)
  • the LNG "revolution" can equalize N. American NG prices with world prices, and
  • there is interest and money in small modular reactors in the USA and elsewhere, a far larger market than Canada alone but one where Canada can lead by being the first market for a cheap, carbon-free source of steam.

You asked "What stopped tar sands operators from using this ... process?"  There's your answer:  the conditions for it coming to market have finally appeared.


Most ICEVs may already be replaced with EVs before Oilcos use nuke generated heat to extract oil from Alberta tar sands.

That being said, Oilcos would than claim that the requirment no longer exist?

That's too bad because small NPPs may be an interesting clean solution for future energy sources, if cost and accepability can be better managed with mass produced units.

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