36 comments on The Status of Canadian Oil Production
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36 comments on The Status of Canadian Oil Production
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Professor Goose,
There's a huge difference in the amount of capital investment required.With the capital investment at $100,000 per barrel per day of level production, this resource costs at least 5 times as much as the most expensive conventional oil production My back of the envelope calculations have yeilded the result that its going to take about $13 Trillion just to get the tar sands to 5,000,000 barrels per day of production, and that's not counting the production costs of syncrude, which are currently about $40 to $50 per barrel.
I'm a landman, not an economist, engineer or accountant. I would welcome any refinement to my figures. But I think thats what we need to look at.
There are other monster problems that need to be addressed too. Water and gas shortages, the probability that the Canadian governments will increase their royalties and taxes, and the huge environmental disaster that is being made by just dumping the used water and mine tailings in slush pits.
Bob Ebersole
I understand a new method of producing Canadian tar sands is being tested - "Toe to Heel Air Injection". If it can be scaled up, the supporters believe it could bring costs and environmental damage down. I don't know aqbout speeding up production. Here a some links.
http://www.bath.ac.uk/chem-eng/staff/profiles/malcolm-greaves.shtml
http://www.oilsandsdiscovery.com/oil_sands_story/pdfs/insitu.pdf
http://www.petroleumequities.com/ITOHOS2005.pdf
http://www.oilsandsreview.com/articles.asp?ID=330
http://www.freshpatents.com:80/Oilfield-enhanced-in-situ-combustion-proc...
Its difficult not to be impressed by the audacity of some of these technologies. Yet I can't help but wonder how much of this is just hype to snare the investors. As near as I can tell from these links some professor in the UK got "80% recovery", whatever that means, in some lab test of the THAI process. Now the PPT presentations are saying they will get that in a field test in 2006. However I couldn't find any indication that such a test had been completed. My question is "80% of what?"
If the technologies work at all in the field, however, they will certainly mitigate any concerns that have been expressed about use of water and natural gas in Alberta.
I was told by the person who sent me the links that this is a one year test. According to him, the test is underway and going well. These are some more recent items:
http://www.petrobank.com/webdocs/news_2007/PBG_2007_06_18_WHITESANDS_P3_...
http://www.marketwire.com/mw/release.do?id=759473
http://www.oilsandsreview.com/articles.asp?ID=449
Gail, the figures I've read say they are producing 6 bbls a day of water for each barrel of syncrude, so the volume of waste has to be at least twice that of the volume of syncrude produced, as the water is mainly used to make a slurry for transportation.
IMHO, 80% doesn't cut it. We stopped using open pits for disposal in Texas about 40 years ago, but not before the seepage trashed huge amounts of shallow sands and surface water. The tar in the tar sands is a coating on the grains of sand and clay, so the amount of waste starts with the volume of waste at least equal to the volume of sand that is processed. It sure would be nice if they handled an environmental disaster before it became the biggest environmental disaster on the North American Continent. The Exxon Valdez is insignificant compared to this.
Bob Ebersole
In the press release they stated a more than 50% oil cut from their first two well pairs, they injected very little water in the process.
Exactly rain song, from the reports gail posted very little water is needed in the new process AND they are getting a higher amount of oil and a higher grade out. Here here for technology.
Where's the beef?!
new process ? air injection, fireflood, insitu combustion, call it what you like (one guy i know called it farflood...... far = texan for fire). this has been tried since at least the 1950's.
some of the problems( as related to insitu combustion in an "oil" reservoir)
1) the combustion process tends to sweep only the upper portion of the oil zone.
2)much of the heat generated is wasted. everything is heated including the rock above and below the oil zone.
3) mobility. the combustion gases have a much lower viscosity than the "displaced" oil.
4) capital requirements although this is most likely a fraction of the capital requirments for tar pit mining.
but much greater than "conventional" oil production (of course the capital requirments for drilling for oil at the north pole are much greater than for "conventional" oil production also.
5) operational problems corrosion, scale deposition, polution, sand production, carbon and wax or tar deposits
hazardous gases (such as carbon dioxide, carbon monoxide and hydrogen sulphide) and tubing and casing failure due to excessive temperatures.
maybe these problems can be overcome but not in time to save us from peak oil. go ahead and park the suv.
Gail, I just bulled ahead inmy answer to you without looking at your links. You have my profound and sincere appology. I sometimes go off a little half-cocked, as i'm sure people on this website have noticed on occassion.
I'm not an expert on this type of recovery-in situ combustion-but I think it has a lot of promise. there are at least two serious questions that this type of production are going to have to answer, besides the cost;
What about the combustion products besides crude, CO2 and carbon monoxide? I know some of the CO2 is going to remain as a miscible solution, but surely some of its going to bubble off. And combustion yeilds othergases that will have to be captured and recycled or sequestered, carbon monoxide being one. Aren't there a bunch of poisonous metals in that stuff, things like arsenic and vandium? God, I wish I'd taken a course or two in chemistry instead of the short stories in Nathaniel Hawthorne in college.
Also, these processes are going to take a whole lot of hydrogen, commonly made from natural gas in chemical plants. How much methane is it going to take per barrel and where do the operators plan to get it?
I know the US Department of Energy did at least one study on in situ combustion of oil to produce some 17 or a
18 gravity oil at Saratoga in Hardin County, Texas on the supra-cap sands, but Mobil Producing of Texas and New Mexico shut it down as uneconomic in the early 1990's. Does anybody know where to find that study online?
Humbled, I remain your most obediant servant,
Bob Ebersole
They used a little natural gas and steam to get the thing started. They did have an energy draw in running the blowers non-stop, thus there were some operating costs not associated with steam injection. I remember gas is compressible, thus you need a pneumatic push to cause the oil to migrate towards the "toe". Forced air combustion has been done before with mixed results, many people abandoned it for steam and VAPEX type solutions.
I have talked to the person who sent me the links about doing a guest post. Maybe we will be able to ask some questions.
That sounds great, I'd be very interested. Frankly , this sounds a little too good to be true.
Where's the hydrogen coming from to decrease th gravity of the crude? How many cubic ft a barrel? How do you make tar unto syncrude that will flow during the cold season. How about some photos and some photos of competing process aolutions ? Can you quote any Keats or Blake so I know you are an estheticially aware person? You know, just the usual Oil Drum Grilling. (sarcanol alert)
Petrobank presented at the CAPP 19th Annual Oil and Gas Investment Symposium June 19 and June 20, 2007 with an update on the Whitsands THAI™ pilot and I recommend listening/viewing that presentation at . They present an in-depth report on the progress in commercializing THAI™. I've been monitoring the work at Whitesands for 2+ years and the pilot facility performance seems to be exceeding all expectations. The produced bitumin is exhibiting a 4 to 5+ degree API improvement over virgin bitumin. Sand production has been a problem and they are currently installing surface sand removal equipment to address this situation. I understand the next three pilot wells will incorporate CAPRI™ with the goal of producing a pipeline shipable product with no diluent. Petrobank recently awarded a grant to the University of Bath for additional downhole process optimization research on CAPRI™, the catalytic cracking enhancement to THAI™. The UofBath abstract can be viewed at . I understand Petrobank plans to submit an application to the EUB for the first 10,000BPD commercial production module before the end of this year with construction to be completed 12 months after permit approval. The permit approval should proceed since the facility uses essentially no NG after pre-ignition steaming, produces a quality industrial water, requires a minimum surface footprint and releases half the amount of CO2 compared to SAGD. I believe we will be hearing a lot more about THAI/CAPRI™ in the months and years ahead.
My apologeses....
CAPP presentation url at
http://www.petrobank.com/inv-corporatepresentation.html
and UofBath abstract at
http://gow.epsrc.ac.uk/ViewGrant.aspx?GrantRef=EP/E059430/1
Seems a little like alchemy to me. I thought you had to add hydrogen to get the tar to the syncrude level-that the whole problem with bitumen is a lot more carbon than crude oils, so the gunk won't flow, like a chunk of unmelted roofing tar. Bob Ebersole
Bob:
You are right that you need to change the chemistry of the butumen to make it flow. The option to adding hydrogen to the bitumen is to remove carbon from the bitumen. This is what happens in the Cokers at Syncrude and Suncor and what is happening in the Reservoir in the THAI process.
Hydrogen will be added to further refine the bitumen at a Refinery down the pipeline.
In the three pilot THAI™ wells currently in operation, the temperature and pressure are so high as to cause extensive thermal cracking...you have, in effect, a down hole coker, in the mobile oil zone, which not only heats the oil, reducing the viscosity to water, but thermally cracks the asphaltenes which are not oxidized in the combustion zone. So, effectively, you are oxidizing part of the asphaltenes to provide the heat for the process and thermally cracking the remaining asphaltenes. Analysis of the exhaust gases confirms the presence of free hydrogen, a byproduct of the thermal cracking. By adding catalyst down hole, you can accomplish catalytic cracking. This ppt presentation at the Alberta Research Council on 10/12/05 presents the science and some of the original laboratory work.
http://www.choa.ab.ca/documents/CHOA_Lunch_Oct2005_05_WEB.ppt
The field full scale pilot tests are complete with three producing THAI™ wells on line (first well in operation for over a year). Work has begun on the three THAI/CAPRI™ wells. In essence, this process enables production of a syncrude with the upgrading taking place in the reservoir with no use of NG and water and half the greenhouse gas emissions. Capex is half of SAGD currently being permitted/constructed in the province and opex is also greatly reduced, not to mention bypassing the need for an upgrader. This technology is now onstream and in continuous operation at Christina Lake. This is a very exciting development for Alberta Province and Canada from both an energy independence and Kyoto compliance perspective.
Thanks Dave. Technology rocks!
Here's a recent article on the guys who are bringing this technology into production...
http://www.oilsandsreview.com/articles.asp?ID=449