Expert Guest Post: Alberta Oil Sands 101 (don’t call it tar sands please… it’s annoying)

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The Following Is An Expert Guest Post from VTZ, a guy who has forgotten more about the oil sands biz than I know. Definately worth your time. Have a great weekend, I'll post the wrap on Sunday.


This is as simple as it gets if you want to understand properly. In short the process is:


Mine->Ore Crushing and Preparation -> Add hot water ->Bitumen with air floats to the top while sands, water and dirt sinks to the bottom -> The stuff that sinks (tailings) is distributed into huge ponds (visible from outer space) which take years to separate the clays from water (they are emulsions that are very hard to break)


The bitumen with air is treated one of two ways so you either do paraffinic froth treatment which creates better oil with removal of the heaviest part of the barrel or naphthenic froth treatment which uses almost the whole volume but is worse quality.


You ship the bitumen with a diluent (to make it meet pipeline specs and pumpable) to an upgrader.


In upgrading, the name of the game is how you manage the heaviest part (often called the bottom) of the barrel. Some people choose to coke it out... some people choose to gasify it... some people use paraffinic froth treatment beforehand with conversion at the end. There are advantages and disadvantages to each.


At an upgrader the first steps are generally as follows:

-Distillation to remove and keep all your diluent (its valuable and gets returned back to the mine) and separate some oil products (sour)

-Vaccum distillation to get different quality oil products (sour)


Then you do a primary upgrading step:


-Delayed coking: Take huge pots and cook oil with them. The oils that are lighter are good products like naphtha, distillates and gas oils (all sour). The outer part on the walls is covered with the heavy junk that gets caked on and makes coke (almost pure carbon but with lots of the worst parts of the barrel in it like metals and sulphur and nitrogen). This is used by Suncor (current), CNRL (future), Petro-Can/UTS (future). You get ~80% liquid hydrocarbon yield because of coke formation.


-Fluid coking: you have a vessel called an LC-Finer which circulates particles of coke and catalyst with a pump such that you have more coke that forms around those particles and you keep cycling in new catalyst and removing coke. Resulting products are the same as delayed coking. This is used by Syncrude (owned majority by Exxon/Imperial Oil (Canadian majority-owned Exxon company) with parts to Canadian Oil Sands Trust (COS-un.to) petro-can, nexen etc. You get ~80% yield because of coke loss.


-Residue Hydroconversion (RHC): This is basically a LC-Finer with hydrogen addition so that you get no coke and is used only by Albian JV (Shell/Chevron/Marathon 60/20/20) because they use the paraffinic froth treatment, which deals with the worst part of the barrel that way. You actually get 102% yield because the hydrogen essentially fluffs up the oil by hydrogen additional.


-Other: Opti/Nexen is using a solvent deasphalter/gasifer within their scheme. BA Energy claims to have new technology that looks like a gasifier with other pots and pans.


Then you need to remove sulphur:


This is done by hydrotreating which removes sulphur by hydrogen addition to form H2S from whichever streams are processed. Some sites like Suncor have separate hydrotreaters for different streams and Albian has an integrated hydrotreater which treats the light distillation and RHC products... Bottom line is all products are sour until they are hydrotreated. Hydrotreating also makes lighter products


Fun fact: Canada is the number 1 producer of sulphur in the world. Syncrude has a huge pyramid (read: millions and millions of tonnes) they have been stockpiling for years that is worth a LOT of money right now because the sulphur market has exploded because of fertilizer prices/demand. Sulphur has sold for as high as 800$/tonne lately although for years it was considered a liability. One of the problems is transportation cost biting into profits. Some of the sulphur is sold to Agrium for fertilizer, for example, which is 5 kms down the road from Shell Scotford Upgrader. Sulphur is typically trucked as a molten liquid although Sulphur can be solidified in block form and stored (like they do at Syncrude).  


Then you blend your products to make synthetic crudes based on distillation cuts and other specs depending on the blend. You generally have a range of products from naphtha, virgin gas oils, light gas oils, other distillates, heavy gas oils and different combinations of light and sweet products, depending on your line up. Your customers are the refineries so you blend according to what they prefer, but also so that you can still manage all of your worst products.


All the cost structures are fairly different and they have more/less CapEx at the expense of OpEx. Some use their own bitumen as energy for gasification (Nexen/Opti is the first) in order to not be exposed to nat gas prices because energy costs represent over 50% of the costs in the oil sands. Yields are different, line ups are different. But the bottom line is oil sands represent steady production over the span of the mine and they are very leveraged to oil price post-construction.






Bitumen Properties and characteristics


Think of bitumen as a heavy and viscous oil. The density is slightly higher than water and bitumen has a density of ~1008-1012 kg/m3 (for the mineable stuff) compared to water at ~1000. If you think of oil in terms of different lengths of molecules, bitumen has more heavy, long strings than WTI for example, or Venezuela heavy or Mexican Maya, etc.


The problem with oil sands is the asphaltenes content which are the heavy, nasty, hard-to-crack, easy-to-coke molecules. This is your number 1 problem and all upgrading strategies are designed to deal with them.


Bitumen generally has high sulphur, as well as metals (like nickel and vanadium), nitrogen, and other things you don’t want to see in a refinery because it fouls your catalyst and requires additional treatment.


Oil sands are the combination of bitumen with sands and clays. This creates a substance that is very difficult to separate, and very sticky. Because the clays are mixed in with the sands, there are many fine solids that cause problems later.




Reserves are a touchy subject because of the way they are classified in Oil Sands. There is no such thing as “proved” reserves until they start producing from a well (for insitu) or break ground in a mine, although extensive drill programs prove out mines just like other mining industries. Reserves will really only be limited in insitu projects by how good the technology becomes because the amount of oil in place is so large. Deposits vary a lot. There can be huge differences in asphaltene content, clay content, and grade of the ore.

Current remaining “reserves” as of this data (NEB, 2004) was 5.2 billion m3 for mining and 22.5 billion m3 for insitu, totaling 27.7 billion m3 (174 billion bbls). These numbers are based on current technologies. As they improve so will the reserves numbers. I have no doubt that Alberta will have more reserves than the Saudis by far. The Saudis claim to have ~260 billion bbls of reserves.

Current Oil sands “ultimate recoverable volume” based on the National Energy Board (NEB) Energy Market Assessment (EMA), 2004 is 11 billion m3 for mining in the Athabasca region and 39 m3 for insitu production from the Athabasca, Cold Lake and Peace River region.  That places the total at 315 billion barrels (6.29 bbl to a m3). Alberta Energy and Utilitiy Board (AEUB) estimates current “volume in place” at 259.2 billion m3 (1.6 trillion bbls). The total “ultimate volume in place” is 400 billion m3. Ultimate is an estimate once all exploration has ceased.

Although I have been only talking about mining, I should note that the same principles of upgrading apply to insitu bitumen although the quality is generally not as good (higher asphaltene content) therefore gasification of the asphaltenes is a more likely alternative here. 




Development is usually done in large chunks every few years because the approvals, engineering, procurement and construction phases usually last 3-5 years. It would take forever to list all the projects in development. Between now and 2015 the projections from the National Energy Board (NEB) based on current project approvals and announced projects is production is expected to grow from ~1.5 million bbls/day to 2 million bbls/day in the “Low Case”, ~3.1 million bbls/day in the “Base Case” and 4.5 million bbls/day in the “All projects Case” (in 2006, when these cases were created. Now I would imagine it’s over 5 for sure although some projects will be delayed due to capital costs so the Base Case is probably still the best estimate.)

The other way people can increase production is via small debottlenecks or reliability projects. Most of these projects happen within 5 years after startup and are good for a 5-15% increase from the nameplate capacity.


Some of the players with the most room for growth between insitu and mining are Suncor (Up to ~800,000 bbl/day from ~300 now), CNRL (up to 750,000 bbl/day from zero currently), Total, (up to 300,000 from zero), Shell/Chevron/Marathon, Petro-Can/UTS, OPTI/Nexen, Imperial Oil and Encana.



Names to know

Pipeline infrastructure: Transcanada, Interpipeline fund, Enbridge, Kinder Morgan

Contractors: Fluor, Bechtel, Jacobs, SNC-Lavelin, Colt/Worley Parsons, AMEC, Stantec

Mining/Upgrading: Suncor, Syncrude (Imperial/Exxon/Petro-can/Nexen/COS-un) Athabasca Oil Sands Project (Shell/Chevron/Marathon), Canadian Natural Resources Limited, Total (bought Synenco and Deer Creek Energy), Fort Hills Partnership (Petro-Canada/UTS Energy/Teck Cominco)

Upgrading Only: BA Energy (private and need financing), North West Upgrading (private and need financing), Nexen/Opti-Canada (they are upgrading insitu product). Ivanhoe Energy has small-scale upgrading technology.

Related: Caterpillar/Finning for the trucks, Molybdenum stocks (Thompson Creek?) because molly is one of the catalyst raw materials and molly is in shortage due to steel demand.

Insitu: Connacher, Nexen/Opti-Canada, Encana, Imperial Oil, Shell, Devon, Conoco, Husky, Chevron, Japan Oil Sands Canada (JACOS), Statoil, Suncor. Oil Sands Quest (BQI) has a lot of land in Saskatchewan and a little in Alberta, but no current plans although it would be insitu.

http://www.energy.gov.ab.ca/LandAccess/pdfs/OilSands_Projects.pdf is a great map of the main players and their locations for both producing, approved and proposed projects. The mineable area is outline in pink and is just North of Fort McMurray.



Sensitivity to Oil Price

Current projects, including sustaining capital, overhead and operating costs (which have increased dramatically) would still be profitable at 65$. NOTE FOR THE FOLLOWING SECTION: My cost data is old (NEB, 2006) from the document below so I’m making a couple assumptions here to scale costs across the board to current costs in 2008. The product qualities are different across the board as well. The table shows various types of insitu production as well as mining/upgrading.






I am scaling everything based on the current op costs for an integrated mining/upgrading from 18-22 to 40-49. The scaling on the op costs is likely more accurate than the scaling on the supply costs. Op costs do not include overheads or sustaining capital.

The Supply costs estimates for 2008 are simply scaled by the same percentage and are likely not accurate because capital is a bigger % of project costs now and the bitumen products are worse than synthetic so the 10% return is likely harder to get without a higher price than is listed. Also, these supply costs could be outdated in a month anyways.

http://www.neb.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/lsnd/pprtntsndchllngs20152006/pprtntsndchllngs20152006-eng.pdf  is where the 2006 data is from

For operating costs in Mining: energy, maintenance & consumables like tires (keep in mind sand is very corrosive to metal and also those tires cost outrageous amounts and are in shortage), labour. Upgrading: Energy, catalyst, maintenance, labour. Insitu is mostly energy costs. In recent quarters with very high gas prices, operating costs for integrated mining/upgrading were probably ~40-50$ Also keep in mind that Alberta (AECO) gas trades at a discount to NYMEX due to distance from market.

http://www.psac.ca/statistics/firstenergy/ for pricing. It shows the AECO discount to Henry Hub as well as other differentials.

http://www.gibsons.com/Section/Customer/Customer_Pricing.aspx Is another good page for product pricing in Alberta based on different crudes and locations and highlights the differences in pricing based primarily on density, and sulphur content. One thing to note is that the heaviest that a crude can be, to meet the pipeline requirements, is 940 kg/m3 and viscosity of <350 cst. So, if your bitumen is heavier or more viscous than that you need to purchase a condensate for example to ship your bitumen. This could cause a shortage of condensate or light crudes in Alberta because of all the insitu producers, therefore more pipeline capacity bringing condensate back to Alberta from the US is being proposed (an example is the Southern Lights pipeline).





Oil Sands Mines are all operated by truck and shovel in the same way as other mines. Also similar to metals mines, three important metrics are strip ratio (the amount of overburden/rocks you need to remove to get to oil sands), pay zone (the depth of the oil sands once you have removed the overburden above) and ore grade (the % per mass of oil sands that is bitumen and not sand/clays/water).


Ore grades from different parts of the mines are blended in order to fall within the acceptable or preferred range. Some ore is not mined because it is too low of grade to process. Ore grades are very important and blends range between 9% (poor) and 13% (very high). Anything above 10.5% is relatively easy to manage, although any blends above 9% could be managed but would require more pots and pans or else recovery suffers.


The truck fleets are huge and run off of ultra low sulphur diesel that is produced by the operators. They use a massive amount of fuel each day for their fleet alone (couple thousand barrels a day). 


Ore Preparation

Ore prep is the first step for processing. Basically the sands are crushed and then broken up even further and mixed with water. This mixture is sent into a huge pipeline called a hydrotransport line which causes shearing against the pipe wall and performs a mechanical separation and mixing of the oil from the sand. The product is called slurry.


Extraction (this is the key separation step)

After coming out of the pipe, the slurry is delivered into huge vessels called primary separation cells (PSCs) or vessels (PSVs). What happens is that the mixture of bitumen, sands, clays and water separates because the water is hot and it releases the sands. Sands fall to the bottom and bitumen froth (bitumen with bubbles from agitation that make it lighter) floats to the top. The water that does not separate from the sands (and some bitumen) is called tailings and sinks to the bottom. There are various other side draws and vessels that still create froth and tailings by flotation. Bitumen recovery ranges from 85%-95% depending on things like fines content and grade.



Froth Treatment (2 kinds)

Paraffinic: You add light hydrocarbons to the froth and it makes the really heavy part of the bitumen agglomerate and settle out in to the bottom as a waste stream. You are left with lighter bitumen and you have effectively done some upgrading in a way by making a lighter product (although you have a waste stream) and less product.


Paraffinic froth treatment is essentially the same as solvent deasphalting, for anyone who has heard of that, which is an oil pre-treatment step with a waste stream that feeds a gasifier and a lighter oil product.


Naphthenic: You add a not as light product in order to get your product to the upgrader and it also acts as your diluent. No bitumen is lost here.




Tailings Management

Tailings are created from the fine solids, which I said caused problems earlier, mixed with water and oil. It creates an emulsion which is hard to separate. Tailings are one of the inevitable parts of the oil sands although there has been lots and lots of work done to try to fix the problem. It is also the part that is most targeted by groups like Greenpeace who are largely uneducated on the issue (funny story is that a couple weeks ago they tried to block a 48” tailings pipe with rocks... didn’t work so well).


Currently the tailings ponds require a long time to settle. Suncor or Syncrude have been in operation for over 30 years and they have not successfully reclaimed a tailings pond to give to the government yet. There is land that has bison and trees and bushes and all sorts of wildlife on it but it is not yet acceptable because the land is not a perfect reclamation.




Pipeline & Bitumen Movement

I talked about this enough in the summary. Basically you need to mix bitumen with a lighter product to get it either to an upgrader or to market. Usually a diluent that can be recycled would be used internally for recycle OR a condensate or synthetic crude (SCO) would be used to go to market (ie a refiner with coking capacity). Encana is shipping their Heavy oil to Conoco Phillips and Husky is shipping theirs to BP with either condensate or SCO. I think both are planning on mods to refineries to be able to handle the heavier crude slate.





I talked about this a bit in detail above but basically there is a LOT of combinations of things you could do here. It’s similar to a refinery, depending on which process units you have you can do different things and they will all be designed differentially and they all have different cost structures. Bottom line is they all need to deal with the heavy part of the barrel (asphaltenes) and they all need to deal with sulphur. The cost structures vary a lot.


Number 1 cost in oil sands is energy; other big costs are catalysts and maintenance.


RHC opex is more expensive due to the hydrogen manufacturing which is very energy intensive but the yields are better


Delayed Coking is cheap opex but you only get 80% yield BUT your products might get a higher price.


For Gasification the trigger is nat gas price. If nat gas price gets too high, more people will likely start building gasifiers to offset their energy costs.


If anyone wants a more in depth discussion of upgrading, ask...



Blending and Products

I described the blending above but basically you are blending individual products to make a crude that meets pipeline specs and customer specs and your customers are the refineries.




Water use, CO2 & Other Environmental Issues

There are increasing pressures all the time from all sorts of groups. Water use is significant and the draw is largely on two rivers: the Athabasca river near Fort MacMurray and the North Saskatchewan river near Edmonton (gogo Edmonton Oilers!). that being said, the draw is nowhere near as significant as many other industrial areas although it is increasing and so is the water use legislation. Water will likely become a commodity and water use will decrease due to the addition of technology which is becoming available.


CO2 – Well everyone knows the pressures to sequester CO2. If it did come, it would be a significant cost and take a long time to implement, although it would likely be manageable. CO2 offset portfolios are also used.


Other emissions are being challenged and reduced all the time.


The government is imposing more and more strict regulations on environmental issues such as water and emissions all the time and it’s foreseeable that more and more costs will be imposed on the companies although I don’t think anything would ever shut down the oil sands. Companies will just add pots and pans, as required and move on.





The royalty scheme is changing in Alberta in a few ways for oil sands.


-The way it used to work: “Royalty volume is calculated using a revenue-less-cost formula. Royalty during the pre-payout stage is 1% of gross revenue; and royalty during post-payout is the greater of 1% gross revenue or 25% net revenue. Royalty is payable in cash. There are approximately 50 projects approved under this Regulation.”


-The royalty scheme is changing and the pre-payout rate goes from 1-5% and the post goes from 25-30% based on oil price which scales.


-The Alberta government is also considering taking “bitumen-in-kind” which means they will be taking a physical commodity but by doing this they also become an energy marketer and/or producer.


Other Challenges

-Environmental and Regulatory – harder to get permits now, water use, CO2, etc.

-CAPEX COSTS!!!! ...are increasing like crazy because there is not enough skilled labour like welders/pipefitters for all the jobs... not enough contractors like Fluor, Bechtel, SNC, Stantec, Colt, etc... market is superheated... steel costs

-OPEX COSTS from energy and catalyst and maintenance


21 Responses to “Expert Guest Post: Alberta Oil Sands 101 (don’t call it tar sands please… it’s annoying)”

  1. 1
    VTZ Says:

    I wrote this post when oil prices were much higher so right now the likely development scenario is probably the “Low case” And potentially even lower.

    Also, since credit has dried up the market for sulphur has also dried up due to reduced fertilizer demand and sulphur prices have tanked as well.

    Keep things like these in mind.

  2. 2
    zman Says:

    V – I just fixed the table. Can you see a problem with any of the links?

  3. 3
    VTZ Says:

    Also, op costs are probably now the 38-42 range rather than the 40-49 because NG prices have come down.

  4. 4
    VTZ Says:

    There are a couple parts that show HTML but other than that the links and text are good. I need to step out, but I’ll be back!

  5. 5
    VTZ Says:

    Other things to keep in mind include the fact that all these projects are currently on hold. Also, the market is in a phase of cooling off because all these projects are on hold although many people are forecasting the costs to come down slowly.

  6. 6
    VTZ Says:

    I’ve been re-reading the post and lots of the sentences have poor grammar. I wrote it all at once and I am an engineer, so forgive me.

  7. 7
    zman Says:

    V – if they wanted good grammar they would have left me long ago, lol. I’m going to archive this on the reports page so we can add to it over time, including a multiples table on the various players and some of their important metrics. Thanks again for writing the piece.

  8. 8
    VTZ Says:

    Yeah, I was thinking of adding or revising some stuff already… I was going to revise all the financial information because most of it is obsolete already due to energy prices. I was also going to add a simple process diagram of blocks to show how it all fits together.

  9. 9
    VTZ Says:

    Just found this as well and outlines all the projects seperately and is VERY GOOD although any projects which have a startup date that are not in construction should be assumed to be delayed or cancelled.


  10. 10
    VTZ Says:

    Also that document was issued in Dec 2008

  11. 11
    tater Says:

    Nice post VTZ! Very much appreciated.

    Z, got the XOM charts done.

  12. 12
    zman Says:

    Thanks much Tater, will have a look.

    V – send me an email if you have edits editions. I’ll put this on the reports tab then with a link back to it in the wrap post tomorrow and one in the Monday post as well.

    OPEC on tape say that 4 non-OPEC’s will be attending the conference including Russia. Sounds like the oil kids aren’t playing nice with the rest of the world this time. Think “severe” cut.

  13. 13
    zman Says:

    Tater – took a look at those charts….fantastic man! Much appreciate the TA and philosophy lessons. On your last comment on volume I have to ask if the dip from upper $81s falling back to $78 as the Senate tanked the auto bailout on low volume is less bearish had it come on higher, more distributional volume. I see the very recent wedge down, but the low point was the selloff day, and to me, that we seem to say that the specialist let it fall in a bad market, not that people were rushing to the exits. Just a thought. Thanks much for the charts, how long did that take you?

  14. 14
    occam Says:

    VTZ – Very informative, thank you.

    What is your opinion of the PBG THAI process, and what success do you think they will have with it?

  15. 15
    tater Says:

    I like your point. I am a big believer in volume, as they say it’s the energy behind the moves, but it does have to be contextualized. That’s one of the reasons I like to use question marks on the comments. It’s not that I am being wishy washy, I’m actually open to the idea that two heads are better than one.
    Really just saw the downtrend in overall volume and gave it a red line without thinking about it too much. Thanks.
    It does take a couple hours to do that stuff, but I’ve been trading the ETF’s lately DUG, SRS, SCC, SKF, so I try to keep track of a couple of the underlying names.
    I’ve also got something of a bug up my ass about XOM because it’s really been confounding me since the middle of summer. Love its option spreads, but I wish I was better at trading it. Maybe I’ll just stick to GE. For some reason that one has been mine. Have a great weekend, time for video cameras and one year old nephews. Good luck to your wife!

  16. 16
    VTZ Says:

    occam – I’m aware of other companies that have tried to form coke in order to partially upgrade oil downhole in the reservoir.

    The idea is sound because it should have much better energy efficiency and higher product value although I’m not entirely sure that the formation is easy to control. To me, the technology still requires some more field results in order to prove its robustness and there is a degree of risk as a result. On the other hand, if the technology is proven in marginal reservoirs and/or the technology is able to consistantly produce higher value product for lower costs then Petrobank offers exception value.

    In terms of their land it is certainly in an area with good leases.

  17. 17
    VTZ Says:

    To add, the problems controlling the reservoir are a result of excessive coke formation.

    Coke can be heated and transfer heat so they are hoping that the coke formation moves from the injection wells to the production ones. They also need to maintain a pressure difference in order to produce from the production wells. If the coke is too thick they might not be able to have a sufficient heat transfer to form new coke or they might not be able to maintain their pressure difference.

  18. 18
    Zman’s Energy Brain ~ oil, gas, stocks, etc… » Blog Archive » Wrap – Week Ended 12/12/08 Says:

    […] The coming week will be dominated by Wednesday’s OPEC decision; more on that in Monday’s post. For a very good primer on the oil sands biz written by our resident industry expert click here. […]

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    Zman’s Energy Brain ~ oil, gas, stocks, etc… » Blog Archive » Expert Guest Post: Alberta Oil Sands 101 (don’t call it tar sands please… it’s annoying)

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