Posted on 06/02/2006 8:44:58 AM PDT by thackney
In the unfortunate argument about peak oil supply, what constitutes "oil" is usually poorly defined. Canada's vast bitumen deposits, mostly located in northern Alberta, offer insight into the difficulty of determining what oil is, defining proved reserves, and peak production. There is little agreement on how this bitumen should be classified. Many folks do it the way World Oil does: with explanations and footnotes.
One of our reasons for not classifying bitumen the same as conventional proved reserves is the fact that it presently relies on large amounts of natural gas and water for extraction and processing, as well as future solutions to growing environmental problems. Should gas or environmental problems become too costly, the 174 billion barrels of Canadian bitumen would become much more expensive to recover using present technology. It would take 476 years at today's production rate of 1 million barrels a day to produce the claimed reserves.
About 20% of the claimed bitumen reserves are in surface mineable sand deposits, with the remaining 80% requiring heat-extraction methods through boreholes, such as the proven Steam Assisted Gravity Drainage (SAGD), which uses injected steam to get the tar-like substance to flow. To date, these two sources have been used about equally for production, but the future lies with SAGD. Natural gas and water are used for creating steam, both in extracting and in processing the bitumen.
The 40 or 50 oil sands developments now being planned or contemplated through 2020 would mean 4.2 million barrels per day of bitumen and synthetic crude (syncrude) production.
Environmental challenges are many. The bitumen contains high metal concentrations and 4.8% sulfur on average. By 2030, sulfur recovery from the expanded oil sands region could generate 10 million tons of sulfur per year, according to a 2004 report by Canada's National Energy Board. Getting rid of this byproduct is a major problem facing producers.
Surface mining creates huge volumes of fluid waste called fine tailings. Solutions are being researched, but there are no demonstrated means to reclaim these tailings. So, ponds must be constructed to be leakproof and last indefinitely. The volume of these is daunting, with current trends indicating tailings in ponds will range between 6 and 10 billion barrels by the year 2020.
Air emissions is yet another complex and challenging problem. The full complement of pollutants, including SO2, NOX, CO, H2S, volatiles (VOCs), ozone and particulate matter are released in the extraction and upgrading process. And then there's the greenhouse gases of methane and CO2. Since Canada is a Kyoto Protocol signatory, the country is supposed to cut CO2 emissions to 20% less than 1990 levels by 2010. The latest data show emissions are running 24.4% above 1990 levels. So, achieving Kyoto targets is not likely. Canada is simply too resource intensive, with its economy sitting near the top of the OECD list in energy and carbon intensity. A new goal for bitumen production might be CO2 reduction on a per-barrel basis, which is already making good progress.
In addition to the environmental burden, there are huge demands made on water and natural gas. The production process uses 2.5 to 5 barrels of water for each barrel produced. However, this has been an improving number and, in any case, the area has good water resources, so, this does not appear to be a major impediment to future growth.
Average gas use is between 1.2 Mcf per bitumen barrel for thermal in situ projects, and 0.5 Mcf for mining and upgrading projects. While not all of this must be purchased, this still means that, at current rates, just 3 million bpd of bitumen production would require more than all of the gas that could be delivered via the as-yet-to-be-built, $7.5 billion MacKenzie pipeline from the Canadian arctic.
Considering the environmental and resource requirements, it seems obvious that the only way the bitumen resource will get produced is through future technologies, not the existing ones that the SEC insists on. But those technologies are indeed being developed.
PetroBank began its experimental Toe-to-Heel Air Injection (THAI) project last month at Whitesands. It began steam injection in vertical wells, which will be followed by air injection for combustion and then production via horizontal wells.
The Vapor Extraction Process (VAPEX) is an in-situ process similar to SAGD, only it uses solvent vapor (typically propane, butane, or CO2) along with a carrier gas (typically methane or CO2), to dissolve and dilute the bitumen. It requires less water and natural gas than steam. It is in testing by an industry research consortium.
Perhaps the most interesting project is the Nexen/ OPTI Canada joint venture, whose Long Lake Project should see first steam in late-2006 and upgrader start-up in mid-2007. Proprietary technology, using distillation, solvent de-asphalting and thermal cracking, separates the produced bitumen into partially upgraded sour crude oil and liquid asphaltenes. Commercially available hydrocracking and bitumen gasification technologies allow upgrading of sour crude into light (39°API), synthetic sweet crude oil, and the asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is a low-cost fuel source and a hydrogen source required in the hydrocracker. The gas will also be burned in a co-generation plant to produce steam for the SAGD operations and for electricity to be used on-site and sold to the grid.
Co-generation of steam and electricity could also benefit bitumen production. However, while there's no doubt in the efficiency increase, there are questions about the market, transmission and infrastructure needed for long-distance electricity transport.
Finally, there is a study by the Canadian Nuclear Society that calls nuclear energy a "viable option from an economic viewpoint," for heat and hydrogen generation for bitumen production and upgrading. While technically feasible, realistically, it's a long way off from garnering public and governmental support.
Of course, if these new technologies become proven, these tar sands will also become proved reserves, by any definition. Truth be told, these bitumen deposits are in a class all their own, and do not fit well into our present ideas of proven and probable oil reserves. And the effect on the public? I doubt that anyone will care whether the stuff that fuels their cars comes from a tar-like substance, or from oil.
http://www.eia.doe.gov/emeu/international/reserves.html
Translation: The world has enormous reserves of oil. Hundreds of years worth of oil. But it might be more expensive than it has been.
Oil extraction...sounds like a fun job.
Preparations under way for upcoming test runs at Ivanhoe Energy's heavy oil upgrading facility in California
Thursday April 27, 8:20 am ET
Canadian Athabasca bitumen on-site for testing
BAKERSFIELD, CA, April 27 /PRNewswire-FirstCall/ - Preparations are well under way in advance of key upcoming test runs at Ivanhoe Energy Inc.'s (NASDAQ: IVAN and TSX: IE) heavy oil upgrading Commercial Demonstration Facility (CDF) in California.
Ivanhoe Energy's CDF is being prepared for a series of test runs that will demonstrate the processing of Athabasca bitumen and vacuum tower bottoms (VTB's) in a "High Quality" configuration. This configuration, appropriate for numerous resource opportunities around the world, including the Athabasca oil sands in Western Canada, produces a more fully upgraded product, as well as maximum amounts of by-product energy.
In order to carry out these runs, a number of upgrades and enhancements to the CDF were required. These upgrades were primarily related to peripheral equipment linked to the handling of raw feed and the processed product, as well as equipment redundancy and back-up for more extended runs.
These upgrades were originally expected to take 4-6 weeks. As a result of the extremely tight markets in the industry for oilfield personnel and equipment and additional minor improvements that extended the original timeline, we have experienced some delay. Ivanhoe Energy currently anticipates commencing the next set of runs at the end of May. Athabasca bitumen has been shipped from Western Canada and is currently at the CDF in onsite storage ready for processing.
The data from upcoming runs will allow Ivanhoe Energy to initiate the site-specific design and engineering for full commercial 10,000 to 15,000 barrel-per-day plants.
Ivanhoe Energy's heavy oil upgrading technology produces lighter, more valuable crude oil at lower costs and in smaller-sized plants than conventional technologies. The technology addresses the four key challenges to heavy oil development:
- the facilities can be field-located and effective at a scale as low as
10,000 to 15,000 barrels per day;
- the value of the upgraded heavy oil is substantially increased;
- the viscosity of the upgraded product is dramatically reduced,
allowing it to be transported by pipeline without the need for blend
oils; and
- significant amounts of by-product energy are produced, as an on-site
source for the production of the steam and/or power needed in heavy
oil recovery.
Do you have a link to the first article? Thanks.
http://biz.yahoo.com/prnews/060427/to144.html?.v=25
The unit produces its own heat and steam as a by-product with it reuses in the process. It's very efficient.
Obviously, both "reserves" and "peak oil" are economic, as well as resource concepts. When the market price increases, reserves rise and peak oil recedes, the latter due to both usage restraint and economically recoverable supply enhancement. (I teach economics, so I take a parochial point of view.)
More expensive in cost, not necessarily price.
IE has an interesting technology, and Robert Friedland has promotional magic; but ECA owns the largest tract of tar-sands AND the largest reserves of natural gas in Western Canada.
And pays a dividend.
I thought what Fischer is talking about was common knowledge until I saw the bovine (porcine?) "peak oil" media coverage. Quite amazing how little people are interested in reality. A vain and incurious lot. Including me, of course.
As Orwell put it, "Ignorance is Strength." And don't forget "Freedom is Slavery."
Actually a decent overview of the subject has to cover a lot more ground. To me it is obvious that Fischer's piece is aimed at those with a very short attention span.
http://www.worldoil.com/magazine/MAGAZINE_DETAIL.asp?ART_ID=2722&MONTH_YEAR=Nov-2005
It depends on what you call "oil."
Another title this could have is, Oil just peaked and no one cared. In most of the doomsday forecasts that the "peak" cottage industry puts out, one thing that is sometimes lost is that innocuous adjective, conventional. It's always conventional oil that is about to peak. The term unconventional doesn't even have a good definition, but it clearly has something to do with profitability. With rising prices, the line of economical production shifts, and the gap between conventional and unconventional oil resources narrows. Most often, conventional oil refers to crude that is above 20° API gravity, and relatively cheap to produce. Everything else that refers to liquid hydrocarbons is, therefore, unconventional "oil."
I took some reasonable numbers from the governmental agencies EIA and IEA, and created the graph on this page. While a bit contrived, and certainly not a forecast (the dates were intentionally left off), it illustrates a point that is not farfetched. If, as Professor Ken Deffeyes has stated, conventional oil production does peak within three weeks of Thanksgiving Day, November 2005, it is possible that unconventional oil could fill the gap well into the future.
Also, I had to cut off the graph's right side so as not to give the impression that a peak will never come - it will. I just don't know when. When it comes to prediction, I prefer to foresee what happened yesterday. Cutting off the right side also prevents having to show that, when a permanent supply shortfall finally happens, it will likely decline at least 1 - 2% per year, while world demand will increase by a similar amount. The growing 2 - 4% wedge will eventually get too large for anyone to believe.
However, it is worth noting that the range of estimates to peak has narrowed over the last decade or so, with the perennial pessimists forecasting a range between next week and five years hence, and the optimists at the EIA and IEA saying that it will be in the 2016 to 2037 range, depending on assumptions of demand growth and the ultimate resource size. Thus, an agreement, or what passes for an agreement, is forming, that a permanent shortfall will occur in the next 11 to 32 years.
We are entering an age where the transmutation of energy from one form to another will become much more common, even strategic. Unconventional liquid hydrocarbons could plausibly contribute 25 million barrels a day within 30 years. A more complete list of unconventional liquids includes GTL-diesel, GTL-DME, starch- and cellulose-based ethanol, tar sands, heavy and extra heavy oils, bitumen, liquids from coal, NGLs and condensate, and refinery gain, which is essentially natural gas that's had its hydrogen robbed in order to upgrade poor quality oils.
So what if conventional oil peaks? As long as unconventional liquid hydrocarbons prolong it.
DME (dimethyl ether) is akin to LPG, an energy rich, environmentally friendly liquid gas fuel, suitable for conventional transportation, fuel cells and gas turbines. It can be made from biomass, coal, natural gas - anything that can be made into methanol. Like hydrogen, it's an energy carrier, and is transportable on LPG tankers. In the past five years, there have been a few pilot and small commercial plants built (about 2.5 million tons/year) and the world's largest fuel-use DME (110,000 tons/year) plant is being built in China.
GTL from natural gas or coal can probably produce a million barrels a day of diesel within 10 to 15 years. In general, all gas-to-liquids technologies are increasingly attractive, because there's no shortage of natural gas on the planet, with about 7,000 Tcf of proven reserves, and at least 2,000 Tcf that is undiscovered - and likely more. Moreover, globally, we are only using it at about 100 Tcf a year; so, the math would say that there's a lot more gas left in the world than oil.
IEA forecasts that oil demand will grow 50% by 2030. IEA also forecasts that unconventional oil (oil sands, extra-heavy oil) will contribute 8 million bpd to world supply within 25 years. And of course, there's the mother of all wild cards - shale oil, with its trillion barrel potential. Shell says it'll make a decision within five years as to whether their development of an in situ shale oil process is commercial.
Reasonable assumptions of demand and supply growth lead to another awkward agreement with the peakers. Since it's likely to take 10 to 20 years to restore a shortfall on a continuing basis, waiting until the peak is obviously too great a risk. Almost by definition, we won't see the peak until it's behind us. The time to form a workable strategy, complete with goals, is now. Such a strategy should be based on existing technologies, and optimistic, but rational, logical extensions of existing technologies. And it should be a plan that would carry us forward for at least a century, if not more.
As I look at worldwide projections for the next 100 years of: population, electricity demand, liquid fuels, transportation and so on - no matter how conservative - the numbers get very large. And going forward from there it's just plain mind-boggling. The risks of delay are great, and the remedies slow and difficult, more so in the midst of a growing, permanent energy shortfall. Market forces? Sure, they'll help, quite possibly, amazingly so. But they only react to the present and are not known for their ability to plan long term. Yes, it's possible that, left only to market forces, unconventional liquid hydrocarbons from all sources will prolong a peak. But I wouldn't bet on it. Rather, we should plan on making them part of our energy future.
Glad to help.
Thank you again. My wife and I are both involved and interested in O&G so the link alone was more than appreciated.
Reading a past article, I was surprised in his saying the lack of refineries was a myth. I disagree with that but it's more involved than the question or answer suggests.
Morgan
That is not exactly what he said.
His myth was "US refining capacity is flat."
This is usually preceded by, or is at least the intent behind, the frequently used statement, "There hasn't been a new refinery built in the US in 30 years." The number of refineries is not particularly important.
Refineries have been expanding within and around their existing locations, and efficiency is also up. As Fig. 5 shows, refining "capacity," however defined, has been trending upward nicely over the last 15 years.
Fig. 5. Capacity and inputs steadily rise.
The US currently refines 15.5 million barrels per day.
Refining and Processing, Weekly Inputs, Utilization & Production, EIA
We import about 2.2 million barrels per day of Gasoline, Kerosene, Jet Fuel and Distillates including diesel and fuel oil.
We produce about 5 million barrels per day in oil.
We import about 10 million barrels per day in crude oil. There is a shortage in both, but the refinery shortage doesn't come close to the shortage we have in crude oil production. Refining does not generate near the taxes or royalty payments that we send in the billions of dollars to foreign governments. We need to open up our nations resources to production and quit letting the environmentalist hold us hostage and fund our enemies.
Disclaimer: Opinions posted on Free Republic are those of the individual posters and do not necessarily represent the opinion of Free Republic or its management. All materials posted herein are protected by copyright law and the exemption for fair use of copyrighted works.