Extracting Heavy Oil: Using Toe to Heel Air Injection (THAI)

This post reflects collaboration between Don, also known as 1observer, and myself. Don is an arms-length investor in Petrobank Energy and Resources Ltd., the company that patented THAI. Otherwise, he has no ties with the company. This post is based on an analysis of publicly available documents. I want to thank Don for all of his hard work that went into this.

1. What is toe to heel air injection technology?

Toe to heel air injection (THAI) is a new method of extracting oil from heavy oil deposits which may have significant advantages over existing methods. The method was developed by Malcolm Greaves of the University of Bath and has been patented by Petrobank. According to the Petrobank website:

THAI™ is a evolutionary new combustion process, that combines a vertical air injection well with a horizontal production well. During the process a combustion front is created where part of the oil in the reservoir is burned, generating heat which reduces the viscosity of the oil allowing it to flow by gravity to the horizontal production well. The combustion front sweeps the oil from the toe to the heel of the horizontal producing well recovering an estimated 80 percent of the original oil-in-place while partially upgrading the crude oil in-situ.

2. Could you explain this a little more?

This method uses a horizontal well with a vertical well at the toe of the horizontal interval. For the first three months, steam is injected in the vertical well to heat the horizontal well and condition the reservoir around the vertical well. After the first three months, air is injected in the vertical well and combustion initiated. The combustion raises temperatures to approximately 400 to 600 degrees Centigrade (751 to 1,111 degrees Fahrenheit). At these temperatures, both thermal cracking and coking occurs. In this process, about 10% of the oil (the coked portion) is consumed. The thermal cracking causes the remaining oil to be upgraded. According to Petrobank's Second Quarter 2007 Financial Report:

Ongoing analysis of the produced oil has shown a continuous upgrading effect. The produced oil is a blend of oil directly affected by combustion and oil that is mobilized and drained by heat conducted into the reservoir beyond the combustion front, which results in a varying quality of produced oil. The produced oil has consistently been of a materially lower viscosity and higher gravity than the native bitumen (500,000 centipoises, 7.6 degree API gravity). The quality of the produced oil has been, at times, up to 16 degrees API and less than 100 centipoises.

Once combustion is started, combustion continues as long as air is injected. In the test wells, it is estimated that this will be about five years. The combustion gasses bring the mobilized oil and vaporized water to the surface, so no pumps are needed.

These are some additional pictures of the process, showing the process in varying stages of development:

3. How much water is used in this process?

Water (and natural gas) are used during the first three months to create the steam which is injected in the well when it is first started. For the remainder of the life of the well (five years in the case of the test wells), neither water nor natural gas is used.

The second quarter report indicates that on the test wells, the oil cut is over 50%. This is in line with what is planned. Since no new water is added after the first three months, the water that is produced is from the ground. According to the quarterly report:

. . . the produced water has been of very high quality, with clean oil/water segregation and minimal emulsion to process. Analysis of the produced water indicates that it will, with minor further processing, be suitable for other industrial uses.

4. Is Petrobank actually able to recover 80% of oil originally in place?

The material on the Petrobank web site indicates that it is expected that THAI will recover 70% to 80% of oil originally in place. If 10% of the oil originally in place is burned in the process, this would leave 10% to 20% of the oil originally in place in the ground. It is not clear from the published material regarding tests whether they are yet at the target level.

According to the Petrobank website, besides yielding 70% to 80% recoverable, THAI can be used in many areas where steam methods cannot:

• Thinner reservoirs, less than 10 meters thick
• Where top or bottom water is present
• Where top gas is absent
• Areas with "shale lenses" that act as barriers to steam
• In general, lower pressure, lower quality and deeper reservoirs than current steam-based processes

By comparison, recovery using current steam processes is estimated to be 20% to 50% in the high-grade, homogeneous areas where steam methods can be used.

5. What tests have been done on THAI?

There was considerable laboratory testing of THAI, before field testing was ever begun. This is discussed in this presentation.

Field tests started a little over a year ago. As of the writing of the second quarterly financial report, there were three well pairs in operation -- one had been in production for over 12 months, one for over 7 months, and one for over over one month.

Each of the pilot well pairs was designed for 1,000 barrels a day of fluid at a 60% oil cut, so each was designed to produce 600 barrels of oil per day. According to the second quarter financial report, what they are actually producing is "up to 2,000 barrels per day and oil cuts of over 50%". Actual production has been choked back from the 2,000 barrel per day level because of sand:

The wells have exhibited high sand production volumes and we have had to run them on very low choke settings, significantly restricting flow rates in order to achieve higher on-stream factors through the surface facilities. A small test sand knock-out vessel demonstrated that the sand can easily be removed from the produced fluids, providing the data necessary to design the larger knock-out vessels required to operate each of the wells at their demonstrated capacity. The first, single well, sand knock-out vessel is expected to be fully operational next week, and we expect to have all three vessels in operation by mid-October. Production rates and on-stream factors are expected to increase significantly with the installation of the new sand knock-out facilities that will allow the wells to operate at their demonstrated combined capacity of up to 6,000 barrels per day of gross fluid, with oil cuts of over 50 percent.

Thus, if the sand knock-out vessels work, oil production is expected to be over 3,000 barrels for the three well pairs combined, compared to planned production of 1,800 barrels per day. Results of the tests indicate that the spacing can be increased from the current 100 meters between wells to at least 125 meters between wells.

6. What additional tests are planned ?

According to the East-West Energy Chronicle Petrobank plans to start three additional test wells in the latter part of 2007. These additional wells will test a potential enhancement to THAI, called CAPRI. With CAPRI, a nickel-based catalyst is added to the well bore, in order to increase the amount of upgrading that occurs. According to Chris Bloomer, Petrobank's Vice-President for heavy oil, "We think THAI is effectively an in-situ coker, and we hope CAPRI could be an in-situ catalytic cracker."

In addition to these three test wells, the company plans to develop an initial 10,000 barrel per day commercial project. Design work and submission of the regulatory application is expected to be completed in 2007. The cost is estimated to be about $150 million dollars, or $15,000 a flowing barrel. It is expected this could be constructed in a year. Since CAPRI has not yet been tested (except in the laboratory), this project would presumably be a THAI-only project.

7. To what extent can heavy oil be upgraded using THAI and CAPRI?

Based on a document from 2002, the hope is THAI can upgrade by 6-8 ºAPI, and CAPRI can upgrade an additional 8 ºAPI. If this can be done, there is the potential to upgrade heavy oil of 8-10 ºAPI gravity to a light oil of 24-26 ºAPI. Medium heavy crude, such as some of that found on the United Kingdom Continental Shelf, could be upgraded from 20-24 to 36-42 ºAPI.

Even if it is not possible to make such large changes in ºAPI, the hope is that the amount of dilutent can be greatly reduced.

8. How does the environmental impact compare to that of current production methods?

It is much less. According to the Petrobank website, the THAI methodology has

• Negligible fresh water use
• 50 percent less greenhouse gas emissions
• Smaller surface footprint and easier reclamation

This is an image of what the above ground operation looks like. One can see that the footprint is quite small.

According to the 2002 document, heavy metals are expected to be reduced by 90+% by this method, and sulfur is expected to be reduced by 30% to 40%.

9. What are the economics of THAI expected to be?

According to the Petrobank website, economics are expected to be much better than current methods:

• Lower capital cost – only one horizontal well, minimal steam and water processing facilities
• Lower operating cost – negligible natural gas, minimal steam generation and minimal water processing - estimated to be 50% of steam assisted methods
• Potential for higher netbacks for partially upgraded product and less dilutent use
• Faster project execution time

According to the The East-West Energy ChronicleThe first commercial project discussed in Question 6 is expected to cost $15,000 per barrel of productive capacity and take 12 months to build.

10. What areas are under consideration for application of THAI technology?

According to the Petrobank website, THAI technology can be used on almost any area with heavy or medium oil. One possible application of THAI is to areas which have already been mined using steam methods. Because of the higher recovery percentage, considerable additional oil is expected to be extracted.

According to the Petrobank web site, Columbia is currently at the forefront of Petrobank's work on THAI outside of Canada. Other countries where agreements are in place are Brazil, Ecuador, Venezuela, and China.

There are many other parts of the world with heavy oil where THAI could also be used, including Texas, Africa, and Russia. This methodology could also be used on medium heavy oils, such as in some of the fields on the United Kingdom Continental Shelf. Since the percentage of oil recovery is so high, the method can be considered a method of Enhanced Oil Recovery, and can be used to extend the life of otherwise-depleted wells.

11. What stands in the way of the wide application of THAI?

At this point, the methodology is not fully tested. The sand problem looks solvable, but it has not been tested in practice yet. CAPRI has not been field tested at all yet. There are various enhancements to THAI and CAPRI that Petrobank would like to look at. This presentation talks about the current status of various Petrobank projects, including THAI.

If THAI is to be used more widely, the technology would need to be licensed to other users. Companies with licenses may also want to do their own tests. Even though the wells are fairly quick to build, it seems likely that it will be several years before any substantial number of wells using this technology can be built, because of the lead times in planing new facilities, getting appropriate permits, and getting pipelines in place. Because of these lead times, it is likely that peak oil will be here before substantial numbers of wells using THAI technology can be put into operation. THAI may help mitigate the down slope, and, if it lives up to its promise, it is possible production may again increase.

It might be noted that there are other new heavy oil technologies under development as well. The booklet Unleashing the Potential of Heavy Oil discusses several other possible techniques, in addition to THAI. One such new technique uses electricity to recover bitumen. The electricity itself could be generated from the bitumen. This method produces no greenhouse gasses in the recovery process. Another method under development uses geothermal energy. These techniques may also be shown to have merit.

12. Isn't THAI the same in-situ combustion process that was used decades ago in California and several other places around the world? [Revised 8/29/2007]

No. In that process, vertical producer wells were arranged in a circle around a central air injection well. Combustion was started in the center, and air pressure was gradually increased to maintain combustion as the burned out central area became larger. There was no directional control--the fire would burn in whichever direction there was least resistance. There were two problems with this method:

• Much oil was by-passed, as the combustion extended in whichever direction it chose. Typical efficiencies were less than 30%, according to Greaves' patent.

• Air breakthroughs to the vertical producing wells were common, because of the air high pressure required in the expanding open area and because of the openings to the surface (vertical producer wells) available for air escape. The hot combustion gasses would rise and explosively break through one or more of the vertical wells. The drop in air pressure would stop combustion.

In 1992, Eugene Ostapovich (Mobil Oil) patented a partial improvement over the original in situ combustion design. Ostapovich used a horizontal producer well, but instead of the single air injector well used by Greaves, Ostapovich used multiple injector wells and multiple vent wells. This arrangement still did not work well, because the gasses could still break through one or more of the vent wells.

In 1995, Malcomb Greaves was granted a patent, improving on the invention of Eugene Ostapovich. In Greaves patent, a horizontal producer well was used with a single air injection well. With this approach, the only places for the hot combustion gasses to escape were (1) the single air injection well (which was blocked by the air or air/oxygen mixture it was injecting) or (2) through the horizontal producer well.

With Greaves invention, THAI, the heat from the combustion front liquefied the heavy oil in front of it, filling the horizontal producer well with an oil/water mixture. The combustion gasses could therefore not escape, except by helping to push the oil/ water mixture through the horizontal producer well. Thus, the combustion gasses could no longer break through to the surface. Instead, they push the oil/water mixture, eliminating the need for a pump to bring the mixture out of the horizontal producer well.

The design of THAI also provides directional control. As the mobilized oil is drained from the reservoir, a vacuum or a low pressures area is created into which air is injected. Draining the oil/water/gas mixture out of the horizontal well keeps pulling the low pressure area forward and moves the combustion in the desired direction.

13. What open issues are there with respect to THAI? [Added by Gail 8/29/2007]

These are some issues we have identified:

• The technology has only been tested for a little over a year. Will the combustion really continue for a little over five years as planned (or perhaps longer, if wells are longer)? What percentage of oil will really be recovered? How much upgrading will actually occur with THAI? With CAPRI? Are there other problems (perhaps with emissions or groundwater pollution) that will crop up several years into the test?

• How widely can this technology really be applied? The three test wells are in one location, but Petrobank believes that this technology can be used in a range of geological conditions. It really needs to be tested in a range of conditions, to know this for certain how diverse geological conditions will affect the process. Additional tests will allow people to better know what percentage of oil will be recovered, how much upgrading will occur, and what emissions or ground water pollution issues (if any) there might be under a range of conditions. Additional tests will also better determine what costs are likely to be.

• Costs of implementation are likely to vary from location to location, because of external factors such as amount and type of geological testing required; amount and type of pollution or emissions control, if any; cost of land; amount of pipeline that needs to be laid; and the amount of royalty payments that will be required. One cannot know whether THAI will be economic in a particular location without a full analysis of the costs in that location.

• In Centralia, Pennsylvania, there has been a problem with a long-burning coal mine, raising the issue of whether this kind of thing can happen with THAI. With THAI, it is necessary to inject air or an air/ oxygen mixture under pressure to maintain combustion. Because of this, the possibility of combustion extending to unwanted areas seems extremely remote. Further testing would clarify whether there is any chance of this being an issue.

• This analysis is not intended to look at the question of whether Pettrobank would profit if the technology is successful. Anyone wanting to analyze this will need to need to look at Petrobank's plans, its proposed business model, patents, competing technologies, regulatory issues, and other issues that might impact the future profitability of the company.

• We have said that THAI might help mitigate the down slope after peak oil, or may even allow oil production to begin to rise again. Without further analysis, it is not clear how much benefit THAI will provide. One issue is whether THAI really works in a wide range of applications. Another is the speed with which it might be applied, in real-world situations. A third issue is how fast the remaining oil supply is depleting. The impact may be only a little, quite late.

• There are a variety of documents relating to THAI which we have not examined, but a person wanting to dig deeper will want to review. These include:




Other References

Besides the links shown above, here are a few other references of interest:

This is a link to Petrobank THAI FAQ's.

This is a link to the presentation from the 2002 launch meeting for THAI.

This is a link to Malcolm Greaves staff profile at the University of Bath.


if you are so inclined... :)

O.K. folks, I've actually run some figures, based on internal data in all the link-to PDF files.

Land Cost: This seems to use about 50% of the surface for a two year period, as opposed to a conventional well which uses perhaps 1 acre for a 20 year period. If I were a landowner I'd want 50% of the surface value as a bonus and liquidated damages. Because of the nature of the equipment, this process precludes ranching or farming during the construction and production. The production seems to drain about 10 acres, with 500' spacing in between producing wells and a 100 meter (329 ft) horizontal leg. So land costs are very probably $1,000 per acre in the Gulf Coast, plus brokerage and title opinion, plus clean up-say $15,000 per unit.

Geophysical, Geological and Generation. These are probably very high. 3D is going to be required, and since its novel technology and possibly will require some test holes for coreing, I'm going to put on $1,000,000 per unit

Well cost: According to the East-West article, the wells cost $15,000 per barrel per day or $7,500,000.00 per 2 producer pair. In the lower 48 wells should be much less expensive, around $2,500,000 for a short horizontal well and two air injection wells about 1650' deep and a 328 ft. horizontal with 329 ft leg, an air injection pump and a settling tank for the sand. I'm not an engineer so this is no more than a guestimate. I'd certainly welcome any refinement of these figures.

Well life. The Petrobank Annual Report picture of the combustion process indicates the fire front advances about 10" a day. I don't know how variable that figure is, in other words can the combustion be controlled easily to either speed up or slow the process. At this rate the test reservoir should last 14 months.The next wells planned are for 125 meters.If this is feasible, the wells should last about 18 months.

Infrastructure costs. In Texas the produced water must be reinjected into a formation not productive of oil and gas, or trucked to a disposal well. Pipelines are generally available fairly close, and one pipeline should handle several wells. In Alberta the operators are just dumping the water in a pit, but there is a shortage of pipelines.

Expected production. It's indicated that actual producion is around 600 bopd per producing well, but apparently the costs were figured on a 500 bopd basis, so 1,000 bopd per unit.

Oil Prices. These are variable depending on the quality of the oil produced, and world oil prices. For purposes of estimating payout and net revenue I used $60.00 bbl.

Royalties: These are probably going to average around 25% in the lower 48, and are 1% before pay-out in Alberta,the 25%. In Texas there is a 4.5% State Severance Tax on oil, but there is an exemption of for heavy oil. In Alberta I'm using a 12.5% Royalty figure, and Texas a 25% Royalty.

Operating expenses should be quite high, as with an operation of this complexity I'm estimating 5%. Its going to take a pumper 24/7 and an engineer, plus work crews as needed. The air injection pumps will require fuel, plus the submersible pump in the horizontal leg and the transfer pumps, plus office overhead.

Thickness of net pay to acheive production levels: unclear from published reports, but I'm guessing 40 ft., depending on the depletion level of the sand.

So what kind of rough economics do I figure?

well cost $7,500,000
G&G 1,000,000
pipeline and infrastructure, 1,000,000
land costs 15,000
10% fudge factor 915,000

total $10,430,000

Gross Revenue
393 day well life, 1200/bbld 4,711,600 bbl
@ $60/bbl $28,296,000.00
royalties 3,537,000.00
lease operating expenses 1,414,800.00

net to investors........................ 23,345,000.00

so, it looks to me about 2.2 to 1 in a two year period
definitely economic, especially since surface mining does not appear to be commercial at this time

well cost...... 2,500,000.00
royalties 7,074,000.00
everything else, pretty much the same, so about 2.5:1

Assuming 1 new producing pair (125 m, 1.2 kbpd, 18 months lifetime, uninterrupted production) installed every week for 20 years:

- we will reach a production plateau around 84 kbpd after 1.5 year (i.e. 70 pairs working all the time and constantly replaced).
- after 20 years, we will have installed 17,000 pairs!
- assuming that each pair has a footprint of 125mx50m (not including auxiliary infrastructure), about 0.33 km2 of land will be used every year.
- in order to reach a production plateau of 1 mbpd lasting 3 years and a half, you will need to install 12 new pairs every week for at least 5 years.

Clearly, the THAI process is not a solution to peak oil but rather a good way to make money.

Hi Khebab, I think I'm missing something here. Why are you using 125 meters for well length? Doing so more than triples the number of wells required. By the way, the three new CAPRI wells, expected to be drilled later this year, are going to be 700 meters long.


the reason I used 100 meters and 125 meters is because the first wells are 100 meters and they were talking about extending the length by 25%,that's using Petrobank's figures. Remember I'm not a engineer, I'm a landman, but it seems extending the horizontal leg and drilling more air injection wells might be a solution-horizontal wells go as far as a couple of miles in deep Austin Chalk. But, since you've got to circulate oxogen to the fire flood, more injection wells might provide a solution, and the air wells are the cheap ones, likely about $200K each completed.

Another way would be to start in the middle of a reservoir, and a drill horizontal well at 180o to the first well, which would get double duty out of the surface equipment and pipelines. Holding down costs is going to be the key to this deal. It might even be possible to drill 4 wells at 90o angles, but I don't know enough about the reservoir geometry to know if its feasible.

Now when you're talking salt dome fields in Texas, sometimes you are talking about miocene and eocene(Wilcox and Frio) sands stacked like a layer cake, sometimes as many as 20 producing sands. Would it be possible to go up the hole and enter another sand? Can these wells produce out of the casing and tubing simutaneously so that the wells can be produced out of a couple of sands at once? This could really help cut the labor costs, and avoid moving equipment.

1observer, do you have any idea if there are depth limitations to the process, in other word, the general range
in which this should be considered. Also, your story suggests that this can be used in sands with a gas cap and water in the sands. Is there a range on the water content?

Frankly, I'm not sure this is economic without a lot of work at cutting costs. Its risky, and a long way from roads and pipelines for not a great return. Maybe I'm way off base in my cost guesstimate, or the potential returns. But 4,716,000 barrels looks like an awfull lot of grease to get out of a ten acre patch of land. Considering the price risk of a general recession, this looks pretty marginal for unproved technology. Bob Ebersole

1observer, do you have any idea if there are depth limitations to the process, in other word, the general range
in which this should be considered. Also, your story suggests that this can be used in sands with a gas cap and water in the sands. Is there a range on the water content?

Bob, I don't know anything about salt domes but perhaps the following will help you. I would like to point out that the current operating wells are 500 meters and have an expected life of over 5 years.

Q : Are there any reservoir characteristics that are crucial for success?

A : As in other vertical drainage processes, vertical permeability is important. Because much of the drainage process in THAI™ operates in the gas phase, we anticipate that THAI™ will be less impacted by reduced vertical permeability than SAGD. Otherwise the technology is very flexible, and in contrast to SAGD, can be applied to deep heavy oil reservoirs, thinner sands and to lighter oils.
Q : Can THAI™ be used in non oil sands reservoirs?

A : Conventional in-situ combustion has been tried in medium gravity reservoirs with some success to increase overall recovery factors. We anticipate that the added control and elevated withdrawal rates achievable with the use of horizontal wells could prove to be very beneficial. Successful physical model runs have been achieved on oils as light as 30° API and also on steam-flooded sands with permeability over 1-Darcy.
Q : Are there depth limitations to the process?

A : In steam injection projects like SAGD, condensation of the steam under high pressure and wellbore heat losses significantly impact the economic viability of the project for all but shallow reservoirs. Because the heat is created in-situ with THAI™, the process can be applied to much deeper reservoirs. Of course, temperature rises with depth and therefore many deep heavy oil reservoirs already benefit from significant in–situ viscosity reduction, but we anticipate that THAI™ could still be used effectively in these reservoirs to raise overall recovery levels and provide the other THAI™ benefits.

Q : What are the typical reservoir parameters used to model the THAI™ process?

A : The typical THAI™ reservoir parameters are:

Oil Saturation = 80% Assumed but the process could be used at saturation levels as low as 50%
Oil Quality = 8° API or greater
Oil Viscosity At Reservoir Temp. = <250,000 cP
Vertical Permeability = 0.5 D
Net Pay = >10m
Shale Content = No continuous lenses, but shale breaks are not expected to be problematic
Clay Content = clay is beneficial to catalyze cracking upgrading reactions.
Thief Zones = not expected to be problematic


Frankly, I'm not sure this is economic without a lot of work at cutting costs. Its risky, and a long way from roads and pipelines for not a great return. Maybe I'm way off base in my cost guesstimate, or the potential returns. But 4,716,000 barrels looks like an awfull lot of grease to get out of a ten acre patch of land. Considering the price risk of a general recession, this looks pretty marginal for unproved technology.

If you're referring to salt domes that may be so but if you're referring to oil sands I respectfully suggest that you re-do the numbers. Thanks for your interest Bob.



A 5.2 year life makes a real difference, and thanks for the info, also a 500 meter reach. I'll be happy to redo and get back with you. There's a lot of stranded oil in Texas, production was basicially uncontrolled before 1936, and the East Texas field was discovered in 1930, the peak of discovery. It was drilled to a well density of 1 well per 6 acres.

The reservoir energy was dissipated. They flared or vented the natural gas, and the absolute open flow caused massive coning. The US Department of Energy Fossil Fuels Department thinks that the average recovery rate on the old fields was around 10% of the original oil in place, and the University of Texas Bureau of Economic Geology says 10% to 20).

The current prospect I'm working up uses a figure of 20% O.O.I.P., but thats pretty arbitrary, but it still yeilds a figure of 100 million barrels OOIP, a hefty target. Its 18 gravity sweet, and an oil pipeline is less than 1/4 mile away, the refineries located about 60 miles as the crow flies. Salt domes have numerous reservoirs, and the one I'm planning to reenter first is apparently about 50 acres, and old reef, so I doubt its suitable. I'd guess at your temperatures of 700o farenheight the lime would cook to cement. But there's plenty more reservoirs, mostly frio and miocene sands, and they might be very suitable they're high silica. I'm trying to raise $500 K to buy up the rest of the formerly productive acreage, about 2,000 acres and I've been shamelessly chumming for investors here because I've only got about $30K of my own to put in on the deal. And I have at least 12 more similar prospects within 200 miles, mostly too big for me to handle, so i'm focusing on one that i think I can put together on my own.

Salt domes and structures control about 90% of the oil production in the Gulf Coast and Louisiana, plus the Gulf of Mexico and the Golden Lane of Mexico. Bob Ebersole

When you do get the acreage together, what do you do then?

I just noticed that 125 m is the distance between producing wells and not the distance between the air injection well and the producing well. From the picture, it looks like the distance is around 500 m. At 10 inches a day, it gives a lifespan of 5.4 years, is that correct?

What is important is the productive lifespan and expected flow rate of a nominal well pair.

From the picture, it looks like the distance is around 500 m. At 10 inches a day, it gives a lifespan of 5.4 years, is that correct?

Correct. So:
5.4 times 365 times 630 bpd of upgraded bitumen (which is the design, actual flow rates have been considerably higher) equals 1.24 million barrels of upgraded bitumen per lifetime of well.


393 day well life, 1200 bbl/d => 471,600 bbl/well

Did I miss something?

yep, my reading glasses. Always check the arithmetic of a middle aged english major, a good rule for the rest of your life. Bob Ebersole


Here's some new rough figures, based on the parameters that Don, 1observer provided me above. These figures are for a three well unit. Once again, I'm an english major, not a mathematician or petroleum engineer. Please double check me as I think this is extremely important. I am happy to admit when I'm wrong, and I really want to know the truth. I'd love to have somebody that actually knows what they are doing on well and project analysis chime in. Bob Ebersole


well cost (2 1500' injectors and a
500 meter horizontal leg well) 7,500,000.00
Geological and Generation 1,000,000.00
pipeline and infrastructure 1,000,000.00
land costs 15,000.00
10% fudge factor 915,000.00
total well costs per unit 10,430,000.00

Gross Revenues
Assumptions, 5.2 year or 1,898 days
$60/bbl net price
1200 bbl/day net production per unit 2,272,600 bbl
Gross sales prices $136,656,000.00

1% until pay-out 104,300.00
25% for rest of productive life 34,137,925.00
5% operating expenses 6,832,000.00
total expenses 42,074,225.00

therefore net to investors= 8:1

This is obviously very economic at these figures. As I said above, if i'm off by a giant factor, please tell me as i think this is extremely important

Bob, Just a few comments. 1. Only one injector well is required per horizontal well. 2. I think it would be better to count on 900 bpd per well pair, not 1200 3. Your $60 bbl net price is probably much to high, at least for now! If CAPRI works as planned you have to determine what is crude with an API of 20 to 25 worth.


Without CAPRI, an API of 15 would be closer to the mark. I do not know about your land cost and other expenses. Perhaps someone else can chime in here. I do know that Petrobank is estimating $15,000 per flowing barrel. SAGD is probably closer to $30,000 per flowing barrel and I've heard of mining projects (Fort Hills) at over $90,000 per flowing barrel.


The reason I threw in a land cost is that Pterobank obviously paid the Canadians for a lease. It may be way out of line, if they'd chime in I'd be happy. But they obviously have purchased some other acreage which is not suitable-almost any project does. A million dollars G&G adds something for their office overhead and 3D seismic, which is very expensive, at least $3 million a square mile, maybe a lot more out in the boonies of Alberta. They are upfront costs. Same way with throwing in a million $ for pipeline and infrastructure. That may be way off base, but they need an oil pipeline to the main oil pipeline going south, roads to truck in equipment, probably work camps for its employees out there. If you spread it out over 1,000 welss it really decreases, but it looks right now like there are enough fewer wells to where its a significant expense. So maybe my extra 3 million or so per well is too much, or not enough, as I said, I'm just trying to figure out if they have something worth persuing-and I have. Its worth persuing, I have decided thay have something that will make the Alberta stuff economic.

And they have something that will possibly make tertiary development here in the states worthwhile, certainly for me and my little plans. I'll be happy to email you what i'm working on so you can take a look, just send me your address to my name, 2004 after at Yahoo.com, all lower case and run together. Bob Ebersole two thousand four at Yahoo.com.

I hate to get more specific because of the spam spiders. My penis saisfies me at its present length, thank you and no, I don't need a new foreign pharmacy or a mortgage.

I just hate to either blindly accept or reject an idea unless I can understand it and look at some figures. That's why I've been so interested in quantifying this a little. And also, Don, I don't want anyone to either accept or reject this as a solution without looking at it themselves, thats why I posted back on drumbeat and have tried to be fair. At any rate, thanks for your help and feedback

But the doomers told me technology couldn't help us! Anyway, thanks for the post Gail, I really like the future of this technology. My only question is who do I invest in to make some bank on it?

I don't understand the statement "the air flow is controlled"... once the air breaks through in the far end of that horizontal... how do you ever shut it in to eliminate the cycling of compressed air.

All that matters in a combustion process is the air to oil ratio.... injected air costs money.

If you had vertical wells, you could simply shut in the one that breaks through and let the combustion advance to the next closest well.

Some of these horizontal well applications are a mystery to me.


With the horizontal well, there is really no place for breakthrough to take place, except up the pipe where oil is expelled. There is sufficient pressure to prevent this. The only air that needs to be injected is the amount to keep the process going - nothing is lost to the outside.

With the many vertical wells, there was lots of place for air to break through. It was a constant problem (my interpretation) to shut the wells close to the breakthrough.

With the horizontal well, there is really no place for breakthrough to take place, except up the pipe where oil is expelled

????- The pipe where the oil is expelled is what we call the "producing well" in my neck of the woods. And if there is sufficient pressure to prevent this, this is what we call "shutting the producing well in".

This is Don's original description of the situation. Perhaps it makes the situation more clear:

To understand THAI/CAPRI and its potential one must first understand the reasons for the seven-decade failure of fire flooding and the limitations of presently employed oil sand extraction techniques.

Purposeful underground combustion started in Russia around 1933...In-situ combustion generates heat in a reservoir through the introduction of air into the reservoir, after which a fire is ignited in the formation near an injection well. The fire and airflow move simultaneously toward the production wells.

Imagine a cylinder buried in the earth at a depth of say more than 75 meters (that's maximum mining depth for Alberta oil sands) that has a radius of 100 meters (arbitrary numbers) and a thickness of 20 meters. In the center is an air injection well for the purpose of supplying oxygen to feed an underground fire. The fire creates heat in the cylinder (reservoir) and burns towards vertical producer wells which surround the circumference of the 200-meter diameter cylinder. Oil mobilizes in front of the burn (fire front) and may or may not make it to a producer well depending upon certain factors.

One can see that due to the cubed nature of the cylinder, increasing levels of air pressure must be introduced to fill the expanding void in the center of the reservoir as the fire front progresses. Coupled with a lack of homogeneity in most reservoirs, herein lies the fundamental flaw in fire flooding. The area of least resistance in the reservoir is typically where the fire front will proceed. Hence the experience that fireflood direction cannot be controlled. To top it off, as the volume of air increases inside the cylinder, more air pressure is applied. The result is often "gas override"

whereby the fire is literally pushed over the top of the slower moving fire front only to be evacuated up a producer well with violent and dangerous results. This gas override, also known as "air breakthrough", is the second major reason for in situ combustion failure.

The hot combustion gases tend to rise into the upper reaches of the reservoir. Being highly mobile, they tend to penetrate permeable streaks and rapidly advance preferentially through them. As a result, they fail to uniformly carry out, over the cross-section of the reservoir, the functions of heating and driving oil toward the production wells. The resulting process volumetric sweep efficiency is therefore often undesirably low. Typically the efficiencies are less than 30%.

"The combustion gasses bring the mobilized oil and vaporized water to the surface, so no pumps are needed."
Still won't these gasses, etc find the easiest route to exit from? I envision bubbling froth of oil, water, and gasses. I must be missing something.
I'm not an oil-guy , forgive my ignorance.

You got it- all that blob of fluid sees is the pressure drop on it. It doesn't care whether the well is vertical, horizontal, or circular helix.


Might I also mention that at shallow depths (above 1,000' let's say)... hydraulic fractures will be induced horizontally such that a cross section can be created which exceeds that of a horizontal 7" well... at probably 2% of the cost.

Gulf oil Company did this in Kentucky in 1960 and achieved a recovery of over 60% of the OOIP from a 150' tar sand.



You used the one word sure to catch my eye...."Kentucky" :-)

Does anyone have good resourses on how much tar sand/medium/heavy oil may be in the lower 48 states.

I have been watching the various in situ extraction ideas for some time, and most of them have fell down on cost/energy used to energy return issues (EROEI essentially). This one seems promising, but again, we don't want to jump on the bandwagon too quickly.

On a non-technical issue, the type of developments we are seeing is why I have thought that the Saudi's will soon up production IF they can up production. They have almost "flushed up" most of the game (competitors) as the bird hunters would say. But they may want to let a few get fully vested in the new technologies and production areas before they come in and essentially chop the legs out from under them. But they can't risk letting the competing ideas really get momentum and efficiency of scale going or the cat may be out of the bag.

What a game, but a damm hard investing environment to figure out, I will say that! :-)


Colorado has more oil than Saudi Arabia but it is in the form of oil shale. Off the top of my head a trillion barrels of uneconomical rock oil. Just worry about the Green River formation and the other 46 states is a rounding error.


I haven`t escaped from reality. i have a daypass.

There's a lot of heavy oil at shallow depths in the lower 48-a hundred billion barrels at least. The oil is under little pressure in the reservoir, and would not pump out at commercial quantities years ago. Modern drilling methods do not detect this oil easily because most states require a driller to set a surface string of pipe which goes through the sands to protect surface water. When the electric well log is run, it starts below this surface casing.The producing level of these wells discussed above is 500 meters, or 1,640 ft.

At Spindletop, the first producing field on the Gulf Coast, the 70,000 barrel a day gusher blew in at 1100' ft, and there were several shows in sands above the production. A few wells have been completed, but never made over 10 to 20 barrels a day. The oil is all 18 gravity or less, and just won't flow into the well quickly enough to be commercial.I think what happened is that the oil close to the surface was degraded by contact with fresh water and possibly microbes, and was passed up for higher gravity crude.

I've got ideas where a number of these shallow oil sand prospects are located, and am certainly willing to help put them together for a share, even have some money of my own and one prospect of 2,000 acres pretty well ready to go

Bob Ebersole

If the scale of that fourth image is to be believed, the combustion zone is involving an area much greater than "10%"

DelusionaL, This might help.



(I'm not an oil guy OK?)
It looks good but I still think this is fluid dynamics. I get the warm thinner oil and flow but the 1(one) piece of oil reservoir rock I have looked at wasn't uniform in the "empty space". Wouldn't oil like water take the easiest route even if downward in this situation? Wouldn't combustion rates be set by oil makeup to maintain proper heating/self sustaining flame front? A mixture of required flame speed vs rock porosity?
The pictures look like chemical osmosis through a consistent medium, I envision something more like lightning, fractured, fissured, racing ahead and essentially sealing in areas that just burn away as the flame front has past by.

DelusionaL, I'm not an oil guy either. The oil does take the easiest route, downward via gravity into the producer (horizontal) well which is one of the reasons for its effectiveness. The producer is placed at the bottom of the reservoir. The reservoir in this case is sand, not rock. Oil sands are porous, rock is not which is why THAI won't work on shale oil. The fire front is so hot (often over 700 C) that it is incredibly robust but slow moving (10 inches per day) so that it leaves very little behind.


So is it the negative pressure area created by the producer well withdrawing oil that controls the direction of the burn also?

If the producer well was north, and the horizontal portion ran on a north-south axis, I couldn't see what would prevent the combustion front from moving east or west, or even south for that matter. The reservoir is not lined with sides to direct the burn after all. I guess this is apparent to others, so I must be missing something.

So is it the negative pressure area created by the producer well withdrawing oil that controls the direction of the burn also?

Hi doug fir, Yes.

I couldn't see what would prevent the combustion front from moving east or west, or even south for that matter.

You said it yourself. The horizontal producer evacuates the oil through gravity along the course of the well due to the creation of a low pressure sink and injected air pressure from behind.. It goes east/west only to the extent that the heat in the reservoir goes. Eventually, at some distance (it appears 50 to 60 meters on either side of the producer) a cooling effect takes place and the oil stops mobilizing. I'm sure that there will be oil left behind but it appears that the process is very efficient.


Thanks for the explanation. D

As I understand it, the longest running well is about a year. So technically, they have no idea as of yet when breakthru will occur.

right and when it does do they seal that part of the horz. well and pull back. It states that combustion gases and vaporized water come to the surface. So why shouldn't the gases bypass the oil altogether? Like sucking on a straw at the bottom of a milk shake.
I'm not an oil guy but this doesn't add up to me. Very slow production (better?)

It states that combustion gases and vaporized water come to the surface. So why shouldn't the gases bypass the oil altogether? Like sucking on a straw at the bottom of a milk shake.

Yes the combustion gases, water AND oil come to the surface together by flowing down via gravity into the horizontal producer well. I believe your straw analogy is more akin to a vertical well? The fluid and gases drain into the horizontal well because the fire front heats and mobilizes the bitumen with the lighter elements mobilizing first. The heavier elements (coke), are deposited at the back of the fire front and provide the fuel for the process. Ergo, the horizontal well is always full of fluid and precedes the fire front at all times. That is why there has been no air breakthrough. The horizontal producer is full and there is no vertical producer to allow air breakthrough either. Again, horizontal wells completely change the nature of fire flood extraction. If there is a flaw in the THAI process, I don't think it resides in this area.


Don, I think I'm missing something or do not understand something.
The gravity drainage/low horz. production well- If the gas(water vapor and exhaust gases(?)) escape like a bubble pump (manometer pump) lifting oil as it rises, then it looks like gas(s) can and do bypass the oil somewhere in the system. Is this just how it is supposed to work? Maybe this is what I'm missing.
You are working very hard and patiently to explain this to me. I might be a lost cause because I grow plants for a living ;)

DelusionaL, This is the first laugh I've had in two days. I wish I could grow plants! OK. If you study the diagram carefully you'll see that the fire front melts the bitumen. As this occurs a low pressure sink is created into which air/oxygen (I'm not sure which but I think it's oxygen) is injected under pressure from the surface. As the bitumen melts, gravity pulls it and water and gases which are co-mingled with the aforementioned fluids into the horizontal producer well. It is impossible for the gases to "escape" or "bypass" the oil while being produced through the horizontal. You should also notice that there is no place for air breakthrough to occur other than through the horizontal and it is in effect a 500 meter long hose full of fluid. Just think of the pressure required to push that out of the way. It won't happen. It might help if you go here
and click on animation. The animation goes through the initial steaming high in the reservoir to mobilize the bitumen and then air injection commences. And it is you who are being patient. I wish I were able to explain this better to you and I'm sure you're not alone. Some of the other comments made suggest to me that others do not understand the process very well. You are just not afraid to admit it. So by all means keep asking. If you can grow plants, you can do anything!


Ok now in this diagram at the toe part it looks like at some point you have air on the production pipe. Does it get sealed (moving away from the flame front) as this happens?

The producer gets sealed in two ways.
1. The producer is always full of fluid (oil and water) mixed in with combustion gases because of the mobilizing and draining via gravity of the reservoir through heat.
2. The heavier elements, coke etc., solidify on top of the producer after the fire front has rolled by. Again DelusionaL, the air pressure required to blow 10's or 100's of meters of fluid out the top of the horizontal producer would be immense. It just is not an issue. I'm hopeful that this explanation makes sense to you. And if not, I'm still here. I must say I admire your persistence. Perhaps it's persistence that will help me learn how to grow plants?


I was a reluctant doomer. Been looking for some good news. I'm enjoying my coffee a little more this morning.
And yes, where do I invest?

Arlo, Petrobank trades on the Toronto Stock Exchange as PBG and in Norway on the Oslo Bors as PBG and on the pink sheets in the US as PBEGF


Thank you Don. Much appreciated.

Don't be too smug.
Here's the best reason I can think of to leave the oil sands alone.

Thank you for the link.

What would it be like for humans to think intelligently instead of stupidly? Good overview--very nice!


I am not sure why you take comfort in the thought of increased production from heavy oil. An economy which is constantly striving to increase its short term wealth is sooner or later going to get into trouble with its resource base. If we can leverage heavy oil, tar-sands, and oil shale, along with improved energy efficiency into several more decades of economic growth at the cost of increase carbon emissions is this really a good thing? I understand the temptation to think so as I have succumbed to it myself. Please, Lord, let me have a few more decades of my ‘normal’ life. But in the long (or maybe not so long) run we have to create an economy whose primary purpose is to preserve wealth rather than to constantly increase it. This is not to say that I think scientific and technical progress will come to an end with the end of economic growth. Nor do I think that there will be zero opportunity for wealth increase in the future. It may be that even in the context of an economy which seeks to maintain long term sustainable methods of economic production, opportunities will arise from time to time to increase living standards though increased efficiency. But to make the desire for constant increases in short term output the driving force of our economic system is insanity. In any rational system of economic production developing methods of agricultural production which maintain topsoil and recycle nutrients so that food production is independent of mining finite concentrations of minerals would be a top priority. Such goals are the kindergarten of sustainable economic production and yet they are not even on the radar screen of the current economic system. Clearly a fundamental paradigm shift is needed and not just techno-fixes which will keep the stock market healthy for X-years longer.

Roger K,
I agree with you that over the next two to three decades (just a guess) we have to adopt a new economic model along the lines of Herman Daly's steady state economy in which economic development,ie, improvements in quality replaces economic growth,ie, increases in quantity. But that transition will require overall economic and political stability as we learn to adjust to lower levels of energy consumption and invest more heavily in renewable energy. If we can buy some time to keep the global economy from a hyperinflationary implosion - don't mean to sound apocalyptic - or major resource wars, we have a chance to accomplish a paradigm shift. I understand, however, the danger of the complacency that can be bred by extending our ability to extract FF a little while longer.

Arlo, your reading of the situation is very good, and your closing line the great warning:
"I understand, however, the danger of the complacency that can be bred by extending our ability to extract FF a little while longer."

We do need to buy a little time....the technology on renewables/alternatives are moving very fast....but.....

If we do after 1997 what we did after 1977, and take the fix of "oil from somewhere, anywhere" and throw the renewable alternatives in the garbage, we lose the whole ball game, pure and simple.


Roger K,

I agree. We live in a finite world. Even if we can "fix" our oil problem for a while, we still have the other problems we had before and they are getting worse - climate change, pollution, fresh water shortages, soil problems, plus all the debt -related problems on the financial side (also related to growth). We need to be finding a more sustainable lifestyle and get rid of the growth paradigm.

Well said.

I think the doomers say that technology won't "save" us from our energy predicament it might "help" us. There is a difference :)

Consuming 30 billion bbl of oil per year we need all the THAI we can get. Not to mention on going growth in China, India, Russia, Brazil et.. el..

I wonder if there were a Manhattan style project for THAI if we could get 90-100 million bbl per day production? That would be cool.

I think THAI is a useful, but limited source of non-conventional oil.

It is not a (IMO) a panacea. It may help, but it will not make up for the looming shortfall of conventional, easy to source and extract light , sweet crude.

It is the loss of the flow of light sweet in the coming years that will be the over-arching problem. A few gains from this technology will merely and ever so slightly delay the inevitable.

Doomers frequently get accused of dissing 'technology'. But ANY of these tecnologies, be it THAI, Ethanol, Thermal depolymerisation etc will simply fail to make up for the loss of flow rates from KSA, Kuwait, Mexico, Russia, UKCS , Norway, North Slope etc.

To carry on as normal requires the discovery of between 4 and 6 New KSAs.

By all means, Try everything and anything to avert disaster, but it will not make up for the looming shortfalls in Light Sweet coming this way soon.

Simmons still has it for me: 'The biggest new fields we will find are now conservation'.

Looks to me that it may be feasible in Siliclastic reservoirs. It will not mobilise Kerogen in Shales. It will be tough to use in almost all carbonate reservoirs.

Some other aspects bother me as well, and could possibly be best answered by a Chemical Engineer and a Reservoir Engineer:

How do you remove the flu-gases created by combustion of hydrocarbons in Air? Same with water? How do you ensure full combustion and not create Carbon Monoxide?

At the stated depths, will the overburden gradient be sufficient to stop, control or confine fracturing when air is pumped in and oil is then burnt, expanding and then resulting in the expected loss of volume as it is extracted?

How do you guarantee that the water table is not polluted?

No doubt it will form one component of the energy extraction mix. But it will not mean energy independence.

There are limits to technology, and growth.

I wonder if a similar approach could be used for in-situ coal gasification/liquidfication. The trick is that by using a horizontal well you get a separation effect. I can't see why a similar geometric approach could not be used for coal.

If you figure this out for coal to hell with tar sands.

memmel, The THAI process requires mobilization of the resource which creates a low pressure sink as the resource vacates into a gravity fed well. This vacating process gives THAI directional control, something that previous fireflooding techniques failed to do. I'm not sure that coal could be mobilized (liquefied) so I'm not confident at all that it could be used for coal.

Here is a link to a company that plans 20,000 BPD production of diesel via Underground Coal Gasification and CTL.

Linc Energy

Their pilot burn was apparently successful and they have access to numerous large, (over 300 million tonnes), stranded coal deposits in Australia.

I'd like to learn more this technology.

Cool thats my bet on where the money is at. Compared to coal the amount of heavy tar left is fairly small. And I'm not knocking technological attempts to extract it. But for fossil fuels in situ CTL is the only real game we have left.
Esp since most of the coal deposits are in "friendly" areas.

The original source of Linc Energy's technology was

Ergo Exergy

A Canadian company that is busy licensing it's technology to many interested parties, BP being the latest listed on their website.

The current state of the game is that there are a variety pilot projects around the world which all look rather promising.

Apparently another Canadian company, Laurus Energy, have identified 2 trillion tonnes of coal reserves in Canada which are suitable for UCG.

3000 billion tons of tons of coal under the North Sea:


I guess we won't have to worry about it ever snowing in the 22nd century.

Thanks for this summary. The THAI process, if successful, may revolutionize the entire industry. However, a lot of question marks are remaining and I'm always uneasy to rely only on official press releases from Petrobank to get informed:

1. What is the range of flow rates expected? can the technology be scale up easily?
2. Can this technology be applied on any type of reservoir? what are the specific constraint on the reservoir features for the technology to be successful?
3. What are the risks? technology success rate.

Khebab, As far as trusting the company I've found them to under promise and over deliver. Still, I spent many hours researching the process by Googling e.g. "Malcolm Greaves + Toe To Heel Air Injection". The results so far obtained by the company are very similar if not slightly more robust than the many experiments carried out at Bath University in England. I might add that oil is being produced everyday from this process and has been for over a year. That oil is trucked out and delivered to a third party. Whitesands has also been visited by numerous mutual fund managers, one of whom I've known since high school (class of '79) and investment houses. Reports by TD Newcrest, Haywood Securities and FraserMcKenzie verify that the process is in fact working with the sand issue being the only problem so far.

1. What is the range of flow rates expected? can the technology be scale up easily?
2. Can this technology be applied on any type of reservoir? what are the specific constraint on the reservoir features for the technology to be successful?
3. What are the risks? technology success rate.

The original flow rate expected was 630 bpd of upgraded bitumen out of a total of 1000 bpd of fluid. It appears that this number will be higher when the sand knockout vessels are installed which should be soon. Air pressure can then be increased.

Any type of reservoir? Again I would suggest reading Greaves but he does suggest that it will work in a lot of different kinds of reservoirs. THAI needs about 10 or 12 meters to operate which is less than SAGD (only one horizontal instead of two).

The risks. That the sand vessels don't work (extremely unlikely) or that it is not as effective on other reservoirs as Greaves thinks.


I might add that oil is being produced everyday from this process and has been for over a year. That oil is trucked out and delivered to a third party.

1observer: do you have any information on the amount of oil produced/delivered? is there third party validation?

Thanks for the info, Charlie

Hi Charlie, No, I do not have any third party validation on the oil delivered. I mentioned in another comment that I personally know a mutual fund manager since high school (funny, he was always on the principal's list) who manages funds in the multi 10 figure range. He has been to the site and reported to me that this was a legitimate process and operation. As well, several brokers have written glowing reports after extensive due diligence and site visits. They include TD Newcrest, Haywood Securities and FraserMcKenzie. I believe too that Raymond James is preparing a report (Petrobank has presented at several of their conferences) but don't hold me to it and I do no not know if they like Petrobank and THAI or not. Finally, as a full time private investor (no clients), I also take from the price action of Petrobank market acceptance. If this were a fraud, we would have known long ago. Yes, markets can be temporarily manipulated, but not for this long. The short interest sharks would have crushed this stock if there were any blood/BS in the water.


I think some of these things will be better known over time. In particular, I thing the range of flow rates will be better known, as more tests are done, and as the process is fine tuned. This is one of the reasons it is hard to ramp up a new technique like this quickly.

Regarding risks, someone working in the oil and gas industry would probably be better able to look at this than Don and I can. One comment I noticed is that "one of the by-products can be free hydrogen, another indication of the very higher temperature". Could this be a problem? Another comment is that carbon monoxide is part of the hot gas mixture. I am not sure what all else are included (besides the obvious ones). The literature seems to indicate that more of the toxic elements are left underground, but there must be some that are discharged.

Two recent sources used for this article that aren't directly from the company are Unleashing the Potential of Heavy Oil Booklet and East-West Energy Chronicle. These feature interviews with a Vice-President from Petrobank, so aren't a whole lot different.

There a several 2002 references given relating to work from the University of Bath. The reason I didn't use these indications as much is they tend to be more optimistic. They were what was hoped for, before any testing was done. For example, the 2002 information cites 80% to 85% expected recovery, where the company's web site cites indicates 70% to 80% expected recovery.

Since THAI is a patented process that one company is working on, it limits what is published from other sources. I have not looked at the patent information shown in the link. Perhaps a Google search would show additional references.


The formation must be at least 30' thick and without shale breaks. I guess its propritary about projected flow rates. I'm also curious as to the area needed for each well and the optimum size of the units, plus the length of the horizontal leg. I'm going to guess and say that it can't cross very big faults, as the displacement would have a big effect in the location of the horizontal leg in the formation.

Thee sand problem might be handled with a gravel pack or some type of custom designed liner, they weren't specific enough to guess, probably on purpose. And , every oil sand is different and every grade of crude. As I'm sure you know, this will probably have to be redesigned for each field, a whole lot of engineering. Depth should'nt matter much, but its probably not suitable for wells less than 500' deep.

This is a very exciting idea and process. If the figures are right, then its going to make the Alberta sands commercial, plus tertiary development on a gang of old Texas fields, and maybe other parts of the world too.The original production probably got less than 10% of the original oil in place

I'm wondering if the figures include the 3D seismic imaging and test bore holes to see if the prospect is right, it strikes me that you'd need a continuous core through the sand.These are not going to be cheap projects, and its very likely to take 10 years or more to bring much oil online. And there's one really major figure to remember-the United States has never produced more than 10 million barrels of oil per day, we currently use 21 mbopd. Its hard for me to believe that we can ever produce even half as much oil as we produced then by tertiary methods, and this oil is likely to be oil that requires at least a $40/bbl price in constant dollars to break even. The era of cheap oil is over, and we're going to conserve and switch to other transportation modes before this provides much help. Those Hummers are going to be antique and classic cars. I expect the cornucopians are going to hype this as the ultimate solution and saviour of the car cuture and continous growth. And that's very doubtful Bob Ebersole


It looks like this may be very useful for actual heavy oil deposits.

This was originally brought up during a discussion on the Canadian Deposits. But will this actually work with the kerogen shale that makes up the Canadian deposits?

Also, what is the effect of this technology on the ground water? The Canadian shale is close enough to the surface to allow for strip mining. For close to the surface deposits, it may really effect the groundwater.



SontagC, No, THAI will not work on shale oil (kerogen) as it is held essentially in rock. Therefore, no mobilization can occur.


Kerogen is the material in oil shale (think Colorado) and bitumen is the material in the tar sands (now referred to as oil sands). Less than half of the oil sands are close enough to the surfce to be mined for processing into oil.

Less than half of the oil sands are close enough to the surfce to be mined for processing into oil.

Actually younggolfer, mining can only go down 75 meters which is about 15% of the total Canadian oil sands resource.


Thanks Gail - I have some questions:

Based on a document from 2002, the hope is THAI can upgrade by 6-8 ºAPI, and CAPRI can upgrade an additional 8 ºAPI. If this can be done, there is the potential to upgrade heavy oil of 8-10 ºAPI gravity to a light oil of 24-26 ºAPI. Medium heavy crude, such as some of that found on the United Kingdom Continental Shelf, could be upgraded from 20-24 to 36-42 ºAPI.

1. It seems that the technology would 'work best' on a certain API range - how would they 'tinker' with it, if they were working in a group of oilfields with disparate APIs?

2. It *seems* like this would have a higher energy return than current SAGD technologies (even though theres no consensus even on those, other than they are low). Any idea on that? Interesting that oil would be a much larger input here than in conventional production which uses primarily nat gas.

3. How much of the worlds known oil fields could be significantly impacted by a technology such as this? I would assume that the higher API, the less impact this tech would have. So how much production *capacity* would be talking about, theoretically?

Thanks - I know the work it took for you to compile all this and its appreciated - anyone else with these answers please chime in...

IS it april 1st?

Can't the heavy ... but unlike Alberta, warm & mobile ... bitumen in the KEY heavy oil source, Venezuela, be lifted by simple screw pumps?

They have so much bitumen there that they might not bother with any form of more efficient technology .. at least initially.

Yes, they use screw pumps in Venezuela.Bob Ebersole

Nate, I don't think the flow rates are affected by the API and for sure no "tinkering" could be done to the API grades in situ.

The energy return should be much higher since much less goes in than other approaches. The real elegance is that the fuel for the combustion (coke) and the upgrading is already present in the reservoir. It's also the part that no one wants at the surface. About 10% of the oil is used to fuel the combustion.

Greaves and Petrobank believe the technology can be used all over the world in many types of reservoirs. The scalability will be much higher than existing technologies because it is much simpler and less costly to implement.


I don't think the flow rates are affected by the API and for sure no "tinkering" could be done to the API grades in situ.

Thanks. By tinkering, I meant, is the technology itself one-size-fits-all, or do they need to change the parameters(and possibly the equipment) at each field depending on its specific viscosity? Hard to imagine they would do the same thing on a field of near bitumen 8 API and a medium crude 20 API.

Nate, I think the process will be same regardless of the field or API. I don't think the design can be modified at all other than say depth or length of producer well. The original intended use was for the north sea and its API is much higher than the Canadian oil sands. So my guess is that it will either work in a given reservoir or it won't. I don't think the equipment will be different but perhaps it will change in scale depending on the field. I might add very little equpment is needed in the first place. Top side facilities are very simple.


Thanks Don - its all very interesting and not something I know much about. At first blush it sounds promising, but so do the cellulosic reports from Iogen. It does sound similar to fire-flooding and I wonder how different it is in the end. It seems it would work best on 'loose' formations as opposed to tight. The good news is the more oil we can recover the more time we have to turn fossil stocks into renewable infrastructure. The bad news is the more fingers in the dike (like this one) the less people worry about a flood..

thanks for your work on this.

At first blush it sounds promising, but so do the cellulosic reports from Iogen.

Agreed. Not to mention that turkey parts plant, and all the others.

I'd really like to see Deffeyes' take on this...

Regardless of the technique, the bottom line is that we are basically mining tar deposits. Fossil fuels can be thought of as a continuum, with light/sweet crude oil in the middle.

On the light end, we have natural gas, natural gas liquids and condensate.

On the heavy end, we have heavy/sour crude, bitumen (tar) and coal.

Light/sweet crude results in the highest yield of conventional Liquid Transportation Fuels (LTF's, gasoline, diesel, jet fuel), in terms of both processing costs and energy input.

The industry is looking toward the light end and toward the heavy end of the fossil fuel continuum to try to meet the demand for LTF's--based on the expectation of an infinite rate of increase in the consumption of a finite energy resource base.

A couple of points to keep in mind:

(1) Our total fossil fuel + nuclear consumption worldwide is the energy equivalent of about one Gb of oil every five days. Worldwide, we consume the energy equivalent of Prudhoe Bay (which will take decades to fully deplete) about every two months.

(2) When Hubbert did his initial Lower 48 projections, based on two URR estimates, he found that a one-third increase in URR only delayed the Lower 48 peak by about five years.

Having said that, I think that we are in the early stages of a never ending energy boom--where we will see an absolutely desperate effort to bring on any and all sources of energy.

Just keep in mind that it will probably be difficult for us to have an infinite rate of increase in the consumption of a finite fossil fuel resource base. I think that it is significant that our most promising "oil plays" appear to consist of tar deposits.

westexas, I agree that the world's fossil fuel use is completely unsustainable even without discussing global warming. And yes, the fact that our most promising "oil plays"
consist of oil sands makes clear the difficulties the world is about to encounter with peak oil. That being said, THAI will quite possibly force many of us to rethink our view as to the downslope in the production rate when the peak is in (I think it has already passed us by) and how good/bad or what the ramifications of such a change may be. I've enjoyed reading your articles on ELM and your push along with Alan From Big Easy on electrified rail and ELP.


A key point that I think some people are missing is the wide--and expanding--gulf between the fortunes of the energy producers and the energy consumers.

As I said up the thread (subject to the Receding Horizons phenomenon), we are in the early stages of a never ending energy boom, but IMO, from the consumers point of view, we are in the early stages of a never ending energy crisis.

I could be wrong, but my bet is that nonconventional production will, for a variety of reasons, only serve to slow, but not reverse, the long term decline in total oil production, and of course from the point of view of importing countries, the situation only gets worse.

But even if I'm wrong, how long would it be before exploding demand around the world absorbed the extra supply?

We need someone to come up with a Toe to Heel Air Injection process that reduces human demand for energy. I'd invest in that. (Except, my 'want' to invest in it, would mean it would have to grow, which defeats the purpose. DOH!)

Brain to Ego Injection?

you're absolutely right that its only going to buy a little time. When I was born in 1951 there were 2 billion people, now there are 6.5 billion and climbing. None of our problems like climate change would exist if our population were the same as the time we were born. And exponential growth means we can only postphone the reckoning by a few more years. If this is a reprieve while the case is on appeal, we need to use it wisely.

The highest prodution in the US was about 10 million barrels a day, we use 21 mbopd currently, of which 14.5 million barrels per day is imported. I can't believe that even 5 mbopd can be added with tertiary production in the U.S., and that would be after 10 years of drilling all out, even though this process looks very promising. The point you've made repeatedly is that once the peak is past, the party's over-all we can do is slow the decline.Bob Ebersole

Tar Sands have the potential of 3 trillion barrels of oil. The success of these kinds of technical "miracles" is with:

- how much of a percentage of total tar sands can be extracted with this. Notice that a small percentage difference has enormous implications: the diference between 10% and 20% is about 300 Gbarrels, or more than Saudi Arabia says it has;

- how fast can you deploy these new techs - it could be marvelous, but already too late;

- how fast they develop in themselves;

- how problems they encounter in development and industry are easily solved;

- how fast they can eventually drill the oil - could this fasten the drilling and make possible for Canada and Venezuela reach more than 10 mbd each? Yes, I agree, its lunacy, but everything's possible, which also implies that it may not be possible.

There are too many variables. So I recommend prudence in the analysis of the future production. Still, my prospects are not good: all of the items I've listed should have positive answers for it to make a difference in our peak oil perspective. Thus, it has a low percentage of success probability (success meaning it will save our civilization from a depression)

Adding to that, I'd like to state something. I've seen some replies applauding this information as something not "dooming". I agree. I like good news as well. Still I wonder if all these tech breakthroughs are nothing more than "jail out cards" that save us from our present irresponsibilities, which gives us a final question: what will happen when all the jail out cards don't come to the rescue?

(and will this be just that timing?)

Does it work in limestone reservoirs? How big a reservoir do they need as far as areal extent? Any idea how the dip in the reservoir affects it?Bob Ebersole

Hi oilmanbob, I'm a big fan of yours. I think you understand Nietzsche's quote "When you stare into the abyss the abyss stares back at you". You've been down but have fought your way back, leaving only your ego behind. Your humanity shines through you.

THAI will not work in limestone reservoirs. It needs reservoirs where the oil can easily mobilize. The wells being used are 500 meters so perhaps that's the extent needed. Not sure about the dip.


Don, Thanks for the complement. No limestone leaves out most of the Permian Basin and the updip Austin chalk/Buda lime on the Talco-Mexia fault zone. But there's a gang of heavy oil in miocene and frio sands pinching out on salt domes and overlying them in Texas and Louisiana. Mobil had a fireflood test at Saratoga in Hardin County in supra-cap sands-its about a 400 acre reservoir, but probably screwed up by the fire flood. I know where a number are, virgin production, but I have no real grasp on the size needed.
Generally, the shallower the reservoir the higher gravity the crude and hardly anythings been produced shallow because it was too heavy to sell. They are mostly missed on electric well logs because of the requirement to set surface casing to protect freshwater, but they're shallow and may not have good enough seals.

Here's an example, but the commercial value is zilch, too many surface use conflicts. The first well in Harris County was drilled at Jackson Hill in 1903, That's about where the Houston Community College headquarters is located near Washington and Waugh. It had a heavy oil show at 90' but never completed. I can't tell you the source, but I read about it in some old history of Houston about 25 years ago.
Click on oilmanbob above and you can find my email.I've got six of them that need to be checked out by a geologist with better surface conditions, and the weather's better than Canada.
Bob Ebersole

Regarding energy return, I think this is one place classical energy return calculations are a little misleading. You certainly want to know how much natural gas is burned, and also how much other energy inputs are used at the surface. The underground oil turned to coke I'm not so sure should be handled in the same way. Burning underground coke is problematic from a CO2 emissions standpoint, but it is not very valuable to society for any other purpose than THAI. So including it in the equation provides the kind of distortion that critics of EROEI who say there are differences in types of energy are concerned about.

One point I noticed in some of Greaves' work was a statement about possibly harvesting energy from the process:

The process also generates power station amounts of energy in the reservoir. If recovered, it could provide most of the energy to run upstream operations and surface facilities, and contribute towards creating a sustainable IOR process.

I'm not quite sure what he had in mind. If this worked, it would seem to improve the EROEI of the process.

From a no engineeering background, and at the risk of making an ass of myself, is it possible that a loop pipe through the feild could be used to create artificical geo-thermal energy to run the facility?

frozen, When you say "run the facility" I take it to mean run the above ground facility operations. Petrobank has discussed harvesting the heat in the reservoir to assist running topside operations but no details. Good thought though. I'm sure that over time, small but significant improvements will be made.


The carbon monoxide being produced in the combustion products is as burnable as natural gas to power the air pumps, or maybe a heat pump from the 700o temperatures produced in the reservoir. The production facilities are going to require power for the air compressors and the transfer pumps to move the oil from the sand settling tank to the pipeline. Also, since this way up in the north woods, an electric generator,Bob Ebersole

Just as blue-sky speculation, but if the air could be replaced by a mixture of oxygen and steam, the composition of the gas produced in the combustion zone would change to include a lot more hydrogen.  This would probably change the reactions occuring in the cracking and in-situ upgrading processes.  This might add value to the product.

Oxygen requires an air separation plant (energy cost), but the steam might be generated from the waste heat from the powerplant (capital expense but no energy cost).

Whatever happened to the cost-graphs to the right of the comments? Price of oil, etc.

I miss them.

They were frozen on the yahoo site as of August 10th. I will check on them and try to get them back.


They're still frozen...amazing.

Not to be a downer but this worries me

At this point, the methodology is not fully tested. The sand problem looks solvable, but it has not been tested in practice yet

And how much can be recovered - for example what is the amount of oil in the lower 48 that can be recovered and will it make a difference with the "tail end" of the peak?

redcoltken, The US has heavy oil but not nearly as much as Canada or Venezuela or Russia.

The Board has adopted the estimates of the Alberta and Energy Utilities Board and, according to it; the ultimate volume of crude bitumen in place is estimated to be approximately 260 billion cubic meters (1.6 trillion barrels).
National Energy Board

How much of that oil THAI can extract I do not know but present technologies are supposedly able to extract 178 billion barrels of bitumen. I believe THAI could add to that number significantly.


Has anyone done any basic estimations of the increase in URR if this is applied to the heavy-medium oil deposits in OECD counties and relatively forward thinking OPEC countries?

A quick calculation:
About 67 billion m3 (Athabasca deposits only) are accessible with SAGD technology (recovery factor: 40-60%). A first guess, is that the THAI process has the same resource base. So the URR could increase between 20% and 100%. Assuming 6.3 barrels per m3 of bitumen, we could get an URR increase between 80 Gb and 130 Gb.

Khebab, THAI's resource base will be a lot bigger than SAGD's. THAI can work in thinner reservoirs (10 meters) and at greater depth than SAGD because the atmospheric pressure increase does not impact on THAI like it does SAGD. As well, THAI is much more robust due to the tremendous heat (often over 700 C compared to SAGD's approx. 200 C) generated in the reservoir. This heat is more able to flash off standing water and push through shale breaks, something SAGD is unable to do (imagine pouring cold water into a pot of boiling water).


This process will access deposits that are not accessible with SAGD. Bitumen runs of only 10 meters and intersperced clay are not a problem. Also, this process is just getting tested in the field. I assume that improvement will be made. The overall increase in producable oil should be significant.


Great summary 1observer,

I am a small holder of PBG shares and would like to point out that if this technology becomes proven it would enable major oil companies using THAI to vastly increase or "book" further reserves. This is huge for them and their shareholders.........


Petronbank listed some technology sharing agreements, am not sure what is being shared. The patent on THAI was recorded in 1990. Canada has a 17 year patent period.

There was something about fire flood being used in the Dakotas:


and in this article:


There are numerous fire flood patents


The by-product of combustion is CO2. It's going to build up and affect the combustion rate.

Yes, but a portion of the CO2 will ultimately go into solution in the heavy oil which would serve to make that oil more mobile. [CO2 flooding is a proven enhanced oil recovery technique.] I do not know on balance if CO2 is part of the problem or part of the solution when assessing the viability of this technology.

Don and Gail, thanks very much for this excellent post. Can I start by asking a few basic questions about the oil sands themselves:

1. What is the normal "clastic porosity", the bitumen / tar saturation level, the water saturation. I'm tryng to get at what would be porosity, permeability, Sw and So.

2. Do these depsosits normally have any form of top seal - I suspect they are just sand cemented with bitumen.

The process sounds revolutionary and elegant. I've always preferred SAGD to mining, and own stock in Encana - who could benefit enormously from this technology.

A cautionary note though. There is sledom such a thing as a free lunch. I can see intuitively that upgrading the bitumen in-situ has many merits - a certain amount of up-grading takes place using SAGD. And this leaves toxic by-products behind - in the ground. And here is where the problem might lie. You are taking a sand that is probably impermeable and removing the cement (the bitumen) and turning it into a nice aquifer. Not only are you going to produce toxic organic substances when burning the bitumen, but the rock is also heated to several hundred degrees in the presence of oxygen that will likley cause the silicate and carbonate minerals to degrade. I presume it rains in Alberta - and the rain fall will likely percoalate into the ground water eventually washing out all this horible stuff into water courses.

Has this type of uncontrolable polution ever been discussed or commented. Otherwise I'd be tempted to rush out and buy shares in Petrobank.

Also is there any information on water / hydrocarbon ratios that may extinguish the combustion process. I'm thinking if there was a lot of irreducible / ground water this turning to steam may eventuallly extinguish the fire.

Euan, After reading your work on Ghawar I'll not pretend to be able to answer the types of questions you need answers for but I will include Petrobank's application to the Alberta Energy and Utilities Board and Alberta Environment. It is about 40 megabytes. I will also add that when I first came across this technology (Thank you WKO) I was skeptical too but the more I investigated the more I believed that THAI would work and it is working. As for the toxic substances underground I think the EUB application http://www.petrobank.com/webdocs/whitesands/whitesands_application.pdf
will help you more than I can.


Don - didn't mean to be bamboozling. My mental image of tar sands is ordinary / loosely cemented sandstone where all the pores are full of bitumen. The bitumen acts as cement - holding the rock together, and makes it impermeable to water flow.

If you take away the bitumen / cement the rock may become permeable and all the water soluble toxic stuff may get washed out into ground water - eventually emerging at springs.

I tried your 40 meg link - will try again later

Q : What are the typical reservoir parameters used to model the THAI™ process?

A : The typical THAI™ reservoir parameters are:

Oil Saturation = 80% Assumed but the process could be used at saturation levels as low as 50%
Oil Quality = 8° API or greater
Oil Viscosity At Reservoir Temp. = <250,000 cP
Vertical Permeability = 0.5 D
Net Pay = >10m
Shale Content = No continuous lenses, but shale breaks are not expected to be problematic
Clay Content = clay is beneficial to catalyze cracking upgrading reactions.
Thief Zones = not expected to be problematic
Q : What are the typical operation parameters for a 500m long horizontal well and 500m deep reservoir?

A :

Fluid Temperatures at bottom hole: 250-300°C
BHP: 4000 kPa
Water Rate: 27m3/d
Oil Rate: 100 m3/d
GOR: 1500
Water Cut: 21%

Euan, I thought this might of some assistance to you. It's from an FAQ on Pettrobanks's site.


Quick thumnbail on Tar Sands Geology (esturine - fluvio-deltaic fine sands bound together by a hydrocarbon sludge...), and some Hydrogeological issues.

As always, the devil is in the detail.


The Athabasca tar sands of northeastern Alberta contain 13 trillion bbl of bitumen in place, 5% of which is accessible by surface mining techniques.^If there is to be significant exploitation of the deeper buried resources, it will have to be done using subsurface [open quotes]in-situ[close quotes] technologies.^Compared to surface mining, these methods are potentially more economic, can be developed on a smaller scale and are environmentally more sound.^The Lower Cretaceous McMurray Formation is by far the richest hydrocarbon bearing unit in Canada.^Overall, it is a transgressive sand and mud dominated unit deposited in fluvial to marine environments.^The main reservoir unit is an estuarine sand, whole complexity makes for an elusive exploration target and a challenging development project.^Successful reservoir management of a subsurface [open quotes]in-situ[close quotes] operation depends on a solid understanding of estuarine stratigraphy and its lithologic heterogeneities.^For the past 20 years, Chevron has been developing an [open quotes]in-situ[close quotes] heavy oil extraction process called HASDrive (Heated Annulus Steam Drive).^Recently, HASDrive and other technologies have been employed on a 77 mi[sup 2] lease with 9 billion bbl of heavy oil in place.^The goal is to bring the lease to a fully commercial 10,000 bbl/day operation by 1997.^In the exploration phase, 64 core hole wells were located with the aid of shallow 3-D seismic and electromagnetic techniques.^The current pilot phase has utilized HASDrive to extract the bitumen from and sand and specialized seismic methods to monitor the development of the steam chamber.

The Mannville Group in northeastern Alberta was deposited during the Early Cretaceous in a south- to north-trending valley system on the pre-Cretaceous unconformity surface. The Mannville Group overlies eroded Devonian carbonates and is overlain by the shale-dominated Colorado Group equivalent. Mannville Group strata are composed of fluvio-estuarine and marine siliciclastic sediments. Hydrostratigraphically, the Mannville succession can be subdivided into four aquifers separated by three intervening aquitards. The four aquifers are, from the base up, the basal McMurray, upper McMurray Wabiskaw, Clearwater and Grand Rapids sandstones. The intervening aquitards are the bitumen-saturated middle McMurray and the Wabiskaw and Clearwater shales. The flow of Mannville Formation water is driven by local topography from recharge at highlands in the southeast and at the Stony Mountain upland in the centre of the study area, to discharge along the valleys of the Athabasca, Clearwater and Christina rivers. In the southwest, the flow in the basal McMurray and upper McMurray–Wabiskaw aquifers is drawn toward the basin-scale drain formed by the underlying Devonian Grosmont aquifer. Vertical flow in the study area is downward, from the ground surface toward the pre-Cretaceous unconformity. Application of the Steam Assisted Gravity Drainage (SAGD) process for in situ bitumen extraction from the McMurray Formation raises several hydrogeological issues: sustaining the large volumes of water needed for steam production; safely disposing of any produced residual water; protecting energy and groundwater resources; and avoiding large-scale cross-formational flow.

There is a technology to use a diluent mixed with steam to recover more than 50% of the oil in place, it also improves the API of the bitumen. One SAGD operator stated they have a modeled high steam to oil ratio to use one mcf of natural gas per barrel. Another operator had plans to gasify coke for use in refining or steam generation. I read a paper that the forced air injection phase of THAI uses 1/2 mcf of natural gas (BTU's) per barrel of biutmen to keep the blowers going. No expensive steam generator infrastructure either. 8-10 API is not pipeline grade oil and requires diluents. The THAI used water in the tar formation or bottom water to generate steam.


The Athabasca tar sands of northeastern Alberta contain 13 trillion bbl of bitumen in place

I think we're missing a decimal in there!



Maybe they mean 13 trillion bbl of sludge and rock mixed together...

This places the citizens of Alberta (and Canada) into an unenvious position when it comes to deciding the energy fate of North America. A popular revolt based upon the amount of money it would take to pipe in fresh water to Alberta may delay rapid expansion.

I am glad its the citizens of Canada who get to decide this one.

I am a citizen of Alberta (and Canada) but I'm not an expert in underground water. Still, I'm not all that worried because, as water moves from the surface to the levels where THAI will take place, it already moves through some pretty bad stuff (ie. tar sands). Yet we don't see much poisonous water in north-eastern Albertan lake country (where I spent my youth).

My understanding is that the water is cleansed by moving through normal porous rock before being discharged to the surface. The diagram on this page makes it seem like the water's journey could take centuries or more.

I have to admit that a THAI operation bordering on my property would bother me a lot less than a tar sands surface mining operation. Besides, Alberta has already decided what to do when it comes to fresh water versus oil production: We produce the oil. (Not that I agree.)

Hmm.. being a native of Southern California I am used to the "water wars" - immense political arguments are held about the allocation of scarce water resources.

If big oil is going full tilt on production it will be in Alberta's best interest to secure as much water rights as it can get and have a good freshwater testing team consistently checking the environmental impact. Then add the cost to any tax consideration with the exported oil.

The Pembina Institute has done an exhaustive (171 pages) study on the water impacts of mining and SAGD operations on the tar sands - I used this as a reference for the EROWI paper (still in review).

Here is the link:
Troubled Water, Troubling Trends

Thanks for that link.

It also gives a nice overview of both SAGD and CSS for us neophytes. THAI is mentioned in the beginning in a general comparison table of different extraction methods, and later on pg 106 in Table 3.2, comparing projected liquid waste disposal amounts of various fields.


You have a good point about what would be left behind, and where it would go. I certainly have not looked at the big environmental application. Having the "bad stuff" underground sounds at least like a step in the right direction. It is better than in the air or in open ponds.

One of the issues we have in all of these discussions is that we live in a finite world. As we use more and more of the resources, we have more and more pollution problems. I could imagine a scenario where Canada decides to produce only the oil it needs itself, or some slightly larger amount, because of pollution problems. Tough luck if other folks want to buy the oil. They can produce it in their own back yard, and live with their own pollution problems.

Having the "bad stuff" underground sounds at least like a step in the right direction. It is better than in the air or in open ponds.

Maybe, maybe not Gail. I'm only speculating here. But a comparison with nuclear waste disposal is probably quite good. No one likes it on the surface - but at least there you know where it is and can keep an eye on ot. Stick it down a mine untreated and uncontained you may be OK for a few years until it starts to escape into the environment - and then there is nothing you can do.

1,000,000 bpd at 600 bpd per well = 1700 pairs of wells - every 3 years?

With this type of in-situ combustion to drive the extraction process, I would guess that the pollutants are much more constrained to the actual site of extraction. With the surface mining, there may be as much as or more environmental pollution but spread out over a larger area. Especially when you start considering the industries that produce the huge equipment involved in the mining, production of giant rubber tires, and on and on.

If-- and it is unfortunately a very big if-- the pollution problems are well researched and dealt with, my seat-of-the-pants guess is that the THAI process could be cleaner from a global perspective.

Best hopes for well thought out and implemented Canadian environmental regulations.

Euan, I'm not an expert in groundwater but would it not follow that if there were serious contamination issues that after a year of combustion we would be seeing some evidence of such? From my research, water contamination becomes a larger issue as the temperature of the combustion goes down, not up.

In addition to the continued upgrading of the bitumen in-situ, the produced water has been of very high
quality, with clean oil/water segregation and minimal emulsion to process. Analysis of the produced water
indicates that it will, with minor further processing, be suitable for other industrial uses.



but would it not follow that if there were serious contamination issues that after a year of combustion we would be seeing some evidence of such?

Well you'd only see it if someone were looking for it. And it may take several / 10s of years for groundwater to leach contaminants from the scorched sub-surface.

Your quote is about the quality of water produced with the "oil" and what I'm talking about is the potential for leaching toxins from the sub-surface residue over a number of years.

From my research, water contamination becomes a larger issue as the temperature of the combustion goes down, not up.

I don't know what the ambient "reservoir" temperatures are here - if we are in permafrost then 0 C, south of permafrost then maybe 5 C. With SAGD, you then produce a halo of isotherms around the wells with temperatures that will vary from 100 to around 5 C. This tempertaure envelope will constrain the range of reactions possible.

With sub-surface combustion, your temperature envelope is everything from around 600 C to 5 C - so this includes a massive low temperature envelope around the margin and a smaller high temperature core.

I can only presume that someone has studied the chemistry of this cocktail. But I'd imagine that combusting bitumen aerobically and anaerobically in the presence of water, air and silicate - carbonate rocks may produce an amazing cocktail of acids (nitric, carbonic, sulphuric and organic) that will leach the mineral matrices. This leaching process will neutralise the acids - but the mobilised elements will stay in solution. I'd also be thinking about the mobility of uranium, which is immobile under reducing conditions (that is in bitumen) - but injecting all that air creates oxidising conditions where uranium ions are extremely mobile. Burning U bearing minerals may also release toxic actinide elements along with radon gas and radium that is highly soluble. This is all speculation, but I'd hope that the State authority conducts proper leaching experiments on cores drilled from the scorched zones and monitors down dip springs for contaminants.

OK Euan, Please bear with me here. Imagine a grid, say like a football field (and with a name like Euan I'm thinking Glasgow Rangers and not the Dallas Cowboys football field!). Suppose we drill horizontals across this field (sideline to sideline) such that after full combustion and extraction has been completed, each chalked 5 yard line or five meter line as the case may be, represents a solid existing barrier of undisturbed oil sand all the way to the bottom of the reservoir. As well, the sidelines demarcate the end of these extraction tubes if you will. In other words, we end up with an underground rabbit warren of tunnels with no exits, no escape for reservoir water. We proceed in this fashion because we speculate that there may be issues in this regard and prudently decide to extract less of the available resource in order to allow a responsible resource extraction policy. What say you?


Don - I've been doing a bit of Devil's advocacy here. If what you say above could be verified, then having combustion zones encased in uncombusted impermeabe tar impregnated rock then the risk to ground water leaching would be reduced.

The main point I am trying to make is that the message of leaving all the toxins underground may be over simplified and misleading. This reminds me a bit of A bomb tests. When they were above surface the hazrd was obvious and measurable. Below ground the problem was buried - for a while at least. In A bomb tests the rock gets melted and fused and becomes less-permeable to ground water - kind of like the opposite of what I would anticipate with fire flooding where the permeability to water will likely increase.

From waht you say above, it sound like at least 50% of the tar has to be left behind in the barrier zones?

Euan, I don't know how big the barriers would have to be but your number seems high. My understanding of the process is that the high temperatures (above 400 C) generated actually leave a much less toxic reservoir than lower temperatures do. Of course, I could be wrong about this. In the end, all these approaches degrade the environment to some extent. If oil sands cannot be counted on what will take its place? Would it be better to burn coal with increasing intensity? Where I live, southern Ontario, the mercury in the lakes from coal burning has been steadily increasing. So I believe that all these discussions should be kept in context. The argument as to whether an approach is "good" or "bad" is a relative one. I know that there are contributors here that think we should not choose between lesser evils. Perhaps that is the correct approach but I do not think it is realistic. When people can chosse between freezing in the dark or not, I know what they'll choose. Thanks for all your thoughts and contributions to this subject. I appreciate it.


How do you get the combustion by-product gases out? The CO2 is going to build up and act as a fire extinguisher!

Hi Ignorant, The CO2 gases are co-produced and separated at the surface. There has been discussion of eventually re-injecting the CO2 back into the reservoir.


I'm confused. Your diagram shows the combustion zone below the surface. Doesn't that produce CO2?

Yes, the combustion below the surface produces CO2 which is co-produced at the surface. Don't forget that air/oxygen is injected to feed the fire flood.


Let's assume this works. What are we talking about as far as Millions of barrels a day from Canada if implemented on a massive scale? 5mbd? 10mbd?

Well antidoomer, My belief is that THAI could be ramped up considerably but it will take a massive, coordinated effort on the part of other oil companies to implement THAI as soon as they are comfortable that it is a legitimate and sustainable technology that can operated profitably. They also must forego the "not invented here mindset" so prevalent in older industries. This will take time. As to the total bpd I don't know but there is a lot of oil in the tar sands and there are lot of heavy oil assets on the planet. My guess is that if pursued diligently, THAI could very well change the nature of the down slope in production. In other words, we could perhaps see oil production decline at much lower rates using THAI than would otherwise have been possible. This would greatly assist society transitioning into a sustainable economic future if indeed that state is even possible.


1observer, I understand the combustion is self-maintained, but other mechanical energy is used. What is the ratio of energy input to the system (the steam heater and gas pump, the product draw, the separation process at the end, the co containment, etc.) to that contained in the crude? Has the net energy been calculated?


Hi peter, I do not know the EROEI of the process. But even to a layman such as myself it would seem to be higher, perhaps significantly so, than existing technology. Petrobank has talked of US$8 to $9 lifting cost per barrel if that is any help to you. As a comparison, SAGD requires anywhere from 1000 to 1400 cu ft of nat. gas per barrel for steam heating. With near term gas at US$7.50 a thousand cu ft you can see how much more efficient THAI is in just this one area.

1observer, such data should be readily available. It is obvious from the photograph the operation is relatively small and contained. All energy entering the system is certainly metered and measured it is not? All we really need to know is the cost in fuel to drill the well holes, and the natural gas or electricity to heat and inject the steam and to pump out the resulting crude. What could be easier?


Agreed Peter, it would be easy for those who have the numbers.
I'm sure horizontal and vertical wells drilled in Athabasca have known costs but I'm not aware of what they are. As far as "All energy entering the system...." Petrobank is not revealing every last detail of their operations at Whitesands for obvious reasons. They are pioneering a game changing technology; why give everything away? But again, the wells run 10 inches per day for five years (when they are 500 meters, the new CAPRI wells will be longer) and use no gas or water other than the first 12 weeks needed to mobilize the bitumen in the reservoir.


THAT'S A BIGGIE.....the waste of natural gas in extracting tar sand has been to me an absolutely huge issue. Anything that can reduce that waste should be looked at long and hard.


I know that there has been investigation of gasifying bitumen to produce the hydrogen for upgrading to syncrude, replacing natural gas.  This would be expensive.  If THAI can replace both the natural gas and the upgrading process with in-situ gases and reactions, it eliminates many of the constraints as well as capital costs.

Hi Engineer-Poet, This project you speak of (Long Lake) is being developed by Opti Canada and Nexen. It should be operational next year. The cost overruns have been atrocious. When viewing the site, it's not hard to see why. Above ground facilities are gigantic. It is essentially a SAGD operation with much more efficient use of the asphaltenes (they replace the natural gas to produce steam) and the bitumen is also upgraded.

The OrCrude™ technology, using distillation, solvent de-asphalting and thermal cracking,
separates the produced bitumen into partially upgraded sour crude oil and liquid asphaltenes. By coupling the OrCrude™
process with commercially available hydrocracking and gasification technologies, sour crude is upgraded to light (39° API)
premium synthetic sweet crude oil, and the asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is
available as a low-cost fuel source, and as a source for hydrogen 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 electric grid. The energy conversion efficiency for our Long Lake upgrader is about 90% compared to 75% for
a typical bitumen-fed coker, which provides us...operating cost advantage.


Wonder if this would work on the heavy oil in Saudi Arabia as well. Don't they have some ridiculous amount of heavy oil as well?

What is called Arabian Heavy crude isn't actually that heavy by world standards - close to 30 api from memory, and getting it to flow through the fabulous Cretacous sandstones reservoirs it is hosted in is not a problem. The high Sulphur content is a problem creating refining / marketability issues.

The Ghawar tar mat is another issue. This is a massive bitumen layer along the E (?) boundary of the field.

I think that there is a pilot steamflood project in the Wafra Field (which I believe is a carbonate reservoir), in the Neutral Zone, between Kuwait and Saudi Arabia.

Oxy Oman:


''Oxy took over operatorship of the Mukhaizna field— one of the largest in Oman—in September 2005. Oxy and its partners are implementing an aggressive drilling and development program, including a massive steam flood project. Development will be fast-tracked with the goal of increasing production 17-fold from 8,500 barrels per day to 150,000 barrels per day within the next few years. By the end of 2006, Oxy increased gross production to 11,000 BOE per day. The partners expect to recover approximately one billion barrels of oil over the life of the project''

You might want to read up about a little town in Pennsylvania called Centralia.



After the death and destruction that caused, the though of underground combustion seems totally insane. Once you light a fire, it has a life of its own.

Once you light a fire it has a life of its own.

Bitteroldcoot, I most respectfully disagree. Please read my explanation as to why previous fire flooding is fundamentally different from THAI. It was added by Gail soon after the article was posted. I also suggest that you peruse the links provided carefully before comparing this process to prior in situ combustion failure. It really is quite fascinating and worth the effort.


I grew up near Centralia and knew people from there. I don't have the words to express the hell created, and the articles I linked to just don't convey it.

I have also spent most of my life trouble shooting technology that produced unexpected results.

I will look of the thread again, but this seems like an insane thing to do.

I don't have the words to express the hell created...I will look of the thread again

Thanks for the feedback Bitter. Like you, I'm hopeful that people will study this subject with an open mind. I think one of the reasons that this process is not well known is the horrible previous experiences with fire floods. It is too easily dismissed out of hand by experienced industry players. They do not yet realize the impact that a horizontal well has on in situ combustion.


Isn't the reason that tar sands are found near the surface is that the overburden didn't seal against the loss of the lighter fractions to the atmosphere?

It seems to me that a pressurized fire near the surface would force all sorts of pyrolysis products to make their way to the surface (as they do in Centralia). Am I missing something here?

Errol in Miami

Hi notintodenial,

Isn't the reason that tar sands are found near the surface is that the overburden didn't seal against the loss of the lighter fractions to the atmosphere?

I don't know about this point. I do know that only 15% of the tar sands are "found near the surface" i.e. less than 75 meters below the surface where oil sand mining takes place. Once below that level, in situ recovery is the only way to extract oil. So, no fire floods are contemplated near the surface. I do not know what the minimum required overburden is for a successful THAI project. Good question. Petrobank's Whitesands project operates at a depth of approx. 3 or 4 hundred meters if I recall correctly.


BOC, you touch on something which has mystified me.  The area of Centralia appears to be drained by a number of streams.  Why not just dam them and flood the valley, putting the fire out?  Or build a dam upstream, and pipe water in for injection wells to keep the fire away from structures and roads.

Thanks, Don!

I am always hopeful of some new technology.

Some comments:

A similar process to THAI was patented on May 1993, US Patent #5,211,230 by Ostapovich. The assignee was Mobil Oil.

Greave's THAI patent, probably based upon the May 1993 patent was filed on June 23, 1995 and the patent granted almost two years later on May 6, 1997. I wonder if Mobil and Ostapovich objected to this new patent?

That's over 10 years ago, so it's not really new and I'm surprised that Shell, Total, BP or others are not using the patent, instead of Petrobank.

You provide questions and answers from Petrobank. Since they have a financial conflict of interest, the answers are not independent.

Please refer to these questions from the Resources Application Group, Alberta Energy and Utilities Board and answeres from Orion Oil (Petrobank) regarding the WHITESANDS Experimental Pilot Project dated Dec 19, 2003.

75 pages of questions and answers

I've skimmed through the 75 pages and there are many challenges for the THAI technology! I remain hopeful. Some of the emissions may be problematic - eg arsenic into the aquifer, sulfur and nitrogen particulates into the air.

Question 5, page 20 of the 75 page document, asked about critical oxygen content to ignite reservoir and sustain the combustion front. Petrobank, in their answer, said that normal air will be injected as opposed to oxygen enriched air.

This 2004 study on THAI
simulated recovery rates versus oxygen concentrations

For enriched air (50 % oxygen and 50% nitrogen), page 6 stated that "Nearly 58% (533.2 MBbl) of the original oil in place (OOIP) is recovered until gas breakthrough and the ultimate recovery is significantly high (74% OOIP (683.1 MBbl))."

However, when normal air (21% oxygen is injected), this lower concentration causes "comparatively lower fireflood front temperatures (Figure 10). The lower flood temperatures result in consistently lower incremental oil productions for normal air". Figure 10 shows the lower temperatures for normal air and figure 11 shows a much lower recovery rate, probable 40% of OOIP.

Even if injecting enriched air causes a significant increase to recovery rates, would the cost of using enriched air be so high that the business model, using THAI, is no longer economically viable?

These are the important questions - what is the cost, in energy, economic and environmental terms, to keeping liquid fuels as center of society. Is this cost greater or less than changing infrastructure? My fear is it is much greater, but if energy and environment are removed from the equation, then it will still appear cheaper.

(Note: Im an agnostic on THAI - because I know very little about it.)

Since the document is long and takes time to download, here was the answer by Petrobank to question 5 c on page 56

Is there any potential for increase in arsenic liberation in aquifers above the production zone due to reservoir heating?


The aquifers above the production zone are the Clearwater Sandstone, the Grand Rapids Formation and the sand layers in the Quaternary deposits including the Empress Formation. The potential for the liberation of arsenic in these aquifers due to reservoir heating would be comparable to the potential release of arsenic due to the creation of thermal plumes at the sites of the steam injection wells and
the production wells. An analysis of the latter was presented in Section B.3.4.1 (Appendix B) of the Application. Based on that analysis, there is a potential that arsenic could be liberated in the aquifers above the heated reservoir. However, any arsenic liberated should not migrate beyond the thermal plume in that aquifer. The thermal plumes in the aquifers are expected to be confined to the development area.

I added the bold, not very convincing answer. The answer may be quite different for a large scale THAI production facility.

Question 8 page 46

There is no assessment of particulate matter (PM). Provide an assessment of PM.

The following answer was 5 pages long.

However, this was the particulate matter summary to the answer

PM Summary
Based on available emission factor information, about 94% of the PM emission from the WHITESANDS combustion sources is expected to result from the vent stack (~128 kg/d). The maximum predicted PM2.5 concentration (assuming all PM is in the PM2.5 size fraction) is 5.1 μg/m3, which is predicted to occur 900 m to the south-southwest of the
stack. The maximum 24-hour average value predicted in the community of Conklin is 0.4 μg/m3.

Representative background PM2.5 concentration in the region of the proposed WHITESANDS Project can be inferred from a review of PM2.5 measurements conducted by Alberta Environment and by WBEA. The measurements indicate a value of 5 μg/m3 is likely to be conservative.

While other model estimates have indicated high PM2.5 predictions for the community of Conklin, these estimates are conservative and include simplifications that will greatly reduce the level of confidence in the results. Specifically, the model was not set up to predict local scale effects within communities and the model results were not presented in this context.

In conclusion, the WHITESANDS Project is expected to result in ambient PM2.5 changes. The maximum predicted concentrations with the addition of a background value are predicted to be well below the CWS. As a follow up, WHITESANDS recognizes the uncertainty associated with the PM emission estimate from the vent stack and will conduct source testing at appropriate intervals to obtain operating data.

The potential for the liberation of arsenic in these aquifers due to reservoir heating would be comparable to the potential release of arsenic due to the creation of thermal plumes at the sites of the steam injection wells

I find this claim a bit hard to swallow. With steam injection I imagine the reservoir temperature will be constrained to 100 C. The steam flood front will form an enevelope around the injection well that may help contain the crap left behind - sorrounded by now plastic bitumen.

Setting fire to the formation is a whole new ball game IMO in terms of temperature and the range of toxin forming reactions that may take place.

At some stage soon I'd guess they will be asked to drill / core the combusted zone and leach the cores to find out what is down there.

Maybe we will soon be so damn desperate for oil that we will happily turn large tracts of Athabasca into Mordor...

That was pretty much exactly my thought. Of course, it could probably be done in Venzuela too, but that naughty Mr Chavez won't allow others to despoil his country and take their natural resources without paying for all the externalities associated with the production thereof...

With steam injection I imagine the reservoir temperature will be constrained to 100 C.

The condensation temperature of steam rises with pressure, and behind the condensation front it can be superheated.  200°C saturated steam has a pressure of about 15.5 bar absolute.

Of course.

Brain jam in operation.

Hi ace, No, THAI is not new. In fact that was one of the factors that I found so encouraging. It had to go through a lot of insightful questioning and testing before it got to the pilot stage. As far as other majors not using THAI they would have seek permission from Petrobank first. As to why they didn't buy it petrobank's answer is

Q : Why is Petrobank the first to try to apply this technology?

A : Petrobank recognized early that THAI™ could be substantially more economical than SAGD because it uses single horizontal wells, does not recycle water and did not depend on low gas prices, and so it acquired the patents to the technology. Unlike larger companies, Petrobank has no sunken investment in SAGD. New technologies are often pioneered by small or medium- sized companies.

As an investor by trade, I understand this implicitly. Big companies are not often good innovators. They are not entrepreneurial either. Too many vested interests and too much bureaucracy stifles THAI like potential not to mention "not invented here syndrome".
But you're right, Petrobank has a conflict of interest which is why I included so many other academic links. And I still hold to decades of investment experience that tells me that if THAI was unlikely to succeed it would be apparent now to the "smart money". Of course smart money can be wrong too whereupon it becomes "new money" otherwise known as "old money that got away". I do not mean to be flippant. It is of course possible that environmental concerns will overwhelm the technology. There is however, no evidence so far that that is the case. The fact that Petrobank is producing near industrial grade water is encouraging. So, I too remain hopeful.

Even if injecting enriched air causes a significant increase to recovery rates, would the cost of using enriched air be so high that the business model, using THAI, is no longer economically viable?

First of all I'm not sure but believe that Petrobank is using oxygen or partially enriched air to fuel the process.

Different Types of Air Separation Processes for Different Applications

The various separation technologies that produce commercially useful products from air are based on differences in boiling points (cryogenic distillation) or on differences in molecular weights, molecular size and other properties (non-cryogenic separation processes)

Non-cryogenic plants are less energy efficient than cryogenic plants (for comparable product purity) but may cost less to build, in particular when the required production rate is relatively small. They are most suitable when high purity product is not required by end-use applications, and when product is not needed full time.

Non-cryogenic processes employ membranes or adsorbents (PSA/ VPSA) to remove the unwanted components of air. They produce oxygen which is typically 90 to 95% pure, or nitrogen which is typically 95 to 99.5% free of oxygen.

At high production rates, cryogenic processes are the most cost-effective choice. Cryogenic processes can produce very pure end products; and must be used to produce liquid nitrogen, oxygen and argon.

Within each technology family - cryogenic and non-cryogenic - there are numerous choices which can be made regarding the specifics of process design, machinery configuration and system control which have capital cost / energy cost / and operational flexibility / plant reliability tradeoffs to define and build the most suitable overall supply system for a specific application.

Now, will this possible cryogenic or non-cryogenic air separation process overwhelm the cost structure? I do not know. Others more versed in this area will hopefully comment but I sincerely doubt that the cost to produce oxygen on site is a deal breaker. The rest of the economic metrics are so favorable to THAI that when I originally came across this issue I did not see it as a major concern. Hopefully this is correct. Thanks for the good questions.


How much O2 is this beast using? For cryogenic O2 plants in 2000 the investment costs were ballpark $20000/tpd for the biggest plants (2000-3000 tpd), and around 12 KW/tpd to produce the O2 (at 1 atmosphere). This would go up somewhat for smaller plant sizes.

PSA or membrane plants would have lower investment and higher power costs. Air Products did propose a 3000tpd membrane plant for coal gasification once, so it probably is possible.

TJ, I don't know that oxygen is even being used here. Petrobank may be just injecting air. The THAI patent contemplates both. Still, even if they are injecting oxygen, it would seem to be cheaper and easier and less environmentally destructive than burning natural gas to boil water to make steam.


Thanks for all your work and insights!

This analysis is really only a first cut. If there are scientific papers, applications of various kinds, and other documents which shed more light on THAI, we certainly should dig deeper. If you have time to look at these and do a post, it would be great.

This is NOT an analysis in any sense of the word. It's simple promotion of Petrobank. There is no critical word to be found, not even a question that is answered by anything else than Petrobank material.

This is a very deep black hole for TOD. Was it too much trouble to go do some research? Do you get paid for this nonsense? Is every single editor asleep these days? For all the reputation this site may have built up, subtract 50% right off the bat. I can't believe things like this. Petrobank's PR material is widespread over the web, there is no need to screw up TOD's name by adding this to it. Nothing here that can't be found elsewhere.

What is not available, and would be a far better focus for TOD, is an independent look at THAI. Well, never mind, too late now.

Spot on, there is no analysis, but 1observer has certainly done a heap of underwriting here.

I, too, have been rather disappointed with some of the front page stories lately.

Not sure it's right to blame the "editors," because as I understand it, most of them don't have the ability to review the stories. Actually, I'm not sure who decides what gets posted, but it seems like most of the TOD staffers don't know what going up until they see it, same as you guys.

We realize this is a problem, and are working on it.

We have a queue for incoming posts. Sometimes (like now) that queue is pretty sparse because people are on vacation, or focusing on non-volunteer efforts. This is a problem for a site without resources, other than goodwill and intelligence.

I can't speak for other contributors but I have several posts Im working on that I think are quite good...;)

(Perhaps I should focus on just one...)

It is difficult when one is dealing with something new like this to cover all of the issues and to know how to balance everything. We start somewhere and gradually add to our knowledge base. If you look through TOD stories, we have had pro nuclear TOD stories, and anti nuclear TOD stories. We have had stories saying that Saudi production is taking a nosedive, and we have had stories saying that maybe it isn't quite so bad.

This is a controversial topic, and we had to start somewhere. Don pulled together a lot of material, and has shared a lot of insights with us in the comments. We have gotten a lot of ideas from readers regarding areas that need to be addressed further. Most people reading the post also look at the comments, so get an idea of what the issues might be. I will add a 13th question, summarizing some of the issues raised by the comments, to try to bring some of these issues back to the post for later readers using this as a reference.

I think it is easy to go overboard in the criticism. Each post can only do so much. This post lays the groundwork for future posts, which will extend the analysis in different directions. If nothing else, it stimulates thought. If those people criticizing the post would like to do some research and come up with additional posts about this subject, that would be great!

I don't think there are any issues of the material in the post being factually incorrect. We give sources for each of the statements made in the post. The reason there is so much material from Petrobank is because that is where the current tests are being run, and that is where the most up-to-date information is. If we go back to material by Greaves from 2002, we tend to get more optimistic views of what might happen, which is why they are not emphasized in this post.

I think we should thank Don for all the work he has done in this area and bringing this issue to our attention.

I think it's plain wrong to turn TOD into a cheerleading site for any industry. And this article is no more than just that. Any editor who would have seen this beforehand would have had to see that.

I looked at some of the THAI stuff last week, when doing the Tar Sands article with Chris Nelder, and neither of us found much beyond Petrobank PR material. The next search will now have a TOD post in that exact same PR category. And I don't see that as such an innocent "we learn as we go along" issue. It's not some bleeping kindergarten around here.

There is, or should be, a minimum level required that this article doesn't even come close to. That drags down the posts that do high-level, intelligent and critical research. When people come to key posts at TOD, they have to be able to trust there is a high level. Or they'll stop coming.

An example:

4. Is Petrobank actually able to recover 80% of oil originally in place?

The material on the Petrobank web site indicates that it is expected that THAI will recover 70% to 80% of oil originally in place.

Excuse me, but that is just not an answer to the question. And you, Gail, should never have accepted it as such. You were played.

One more thing: THAI is not new, as we all know. Saying that Petrobank is the only firm applying it, while Shell, Imperial et al do not, does in no way sync with the enormous advantages and gains that Petrobank would have you believe in. If their claims were true, everybody else would be hugely stupid, asleep, drunk and sedated.

And no, I don't think we should thank Don for propagating the things he has financial interests in.

I think we should thank Ace and Khebab for their comments, and humbly ask them to perhaps write a post on THAI that can wash this blemish from TOD.

Your example shows that you are not reading very well. If you read the full response to QUestion 4, it continues with:

It is not clear from the published material regarding tests whether they are yet at the target level.

What this says is that we don't know whether they are at the 70% to 80% level. If we had said what you claim we said, and left it at that, I agree, it would be a problem. But we didn't, so read the whole response before you complain.

If you notice, I have already specifically asked Ace about writing a post to look into this more. I have also more generally asked that people with an interest in researching it more write posts about it. We need more constructive analysis. Criticism, without even bothering to check the facts, is pretty useless.

You probably should just shelve this for four years. They are only one year into what amounts to a five year pilot plant run, after all. They literally at this point only have computer simulations to go on, and really have no idea about recoveries, environmental effects, or what have you. For instance, if a year from now they start getting SO2 out with the exhaust gases the additional investment for cleaning will probably kill this idea dead.


I have large problems with what you wrote here, I don't like, nor deserve, to be taken for a fool. And you just did.

You -typically- pick out of what I said that which you think you have a response to. And even that fails.

As for the question in question, why would I first want to read the PR promo stuff, and only after that go to something that actually makes sense? Is that what TOD is all about?

Do you have any idea at all what this post is? You've been had, you are a vehicle for money. If that makes you happy, soi. I think it's ridiculous.

What this says is that we don't know whether they are at the 70% to 80% level.

No, that is bullfrog, you, Gail, don't even know if they're at a 20% level. And THAT is the problem here. You put up a post, and know far too little on the topic. So you have some investor dude come in, and all looks good at the surface. How much again did you get paid?

Are you going to answer me at all, or do you think it's a good idea to leave to at this non-answer?

The title of your post starts with: "A new method...." Not even that is true, nothing new about THAI.

I think my comments so far deserve a lot more attention than you give them. You have no answer to anything, and that is exactly the problem that I have with this post, and I'm not the only one. I strongly suggest you start with the questions I've asked in the post you just reacted to. Strongly, as in: I want answers. As in: Why doesn't Shell use THAI? My questions were clear in the last mail, no need to repeat. And I don't suffer either stupidity not insults lightly. I have both from you now.

A check on Google indicates that there are 103 posts on TOD with both the words troll and HeIsSoFly. I suspect that is more than a co-incidence. Why don't you find something worthwhile to do with your time?

Gail I like the stuff you usually do but this aint one. When I came across the article the first thing I see is ARMS LENGTH INVESTOR, I never heard of such an animal, I have heard of the word PROMOTER though and like HeIsSoFly I think you have been had. Read Don's response to my post re Habenaro it reeks of an investor's defensiveness. The next post is not even answered.

If you don't like it don't read it. Your quite serious for someone named "heissofly"

I have large problems with what you wrote here

After starting the conversation with:

"This is NOT an analysis in any sense of the word. It's simple promotion of Petrobank....This is a very deep black hole for TOD. Was it too much trouble to go do some research? Do you get paid for this nonsense?"

what did you expect?

The title of your post starts with: "A new method...." Not even that is true, nothing new about THAI.

Then why was research into the technique being published by the Institute of Chemical Engineers in 2000 , 2003, and 2006, as well as the Journal of Canadian Petroleum Technology in 2005?

Or do you know this field better than they do?

PR promo stuff

Most of the information in the article appears to come from either the published research out of Bath - which has presumably been through peer review - or from the most recent quarterly report of the company, which is an official document filed with regulators who are bad people to lie to.

There's general unhappiness that the Bre-X trial just ended in acquittal of the only surviving defendant, making right now a bad time to play pump-and-dump with Canadian regulators.

I think my comments so far deserve a lot more attention

Fortunately, we as readers get a say on that. And in general...

I strongly suggest you start with the questions I've asked in the post you just reacted to. Strongly, as in: I want answers.

...people who angrily demand attention very rarely deserve it.

Gail, Don, excellent work. I for one am glad to see someone recognize that technological developments can make a difference.


This is NOT an analysis in any sense of the word.

Perhaps some of our readers, like yourself, are very familiar with THAI technology. This is the first time I saw it graphically represented and I learned a bit. Im not overly enthused by it as it seems the jury is still out. Still, it COULD be meaningful.

Gail posted something from someone with knowledge in the industry-not as an analysis, but rather as an information and beginning for discussion, clearly showing that the information came from Petrobank. I assure you, neither Gail, nor anyone here is receiving one red cent from anyone, and indeed our own renumeration here can be counted only in the currency of facilitating energy knowledge and awareness and pushing forward a logical, scientific based quiver of best solutions.

Without speaking for the rest of staff, I am 100% certain this site will never sell out to any corporate interest or specifically advocate any 'technology', unless it is in a broad macro sense, such as raising CAFE standards, having a gas tax, etc.

If you would like to spend the time to offer an independent, more empirical look at Toe to Heel Air Injection methods, please send us a draft.


Nate I see similarities between this THAI and a process by Habanaro which has seemed to have not lived up to expectations. I would expect Don to be familiar enough with what Habenaro was doing to give some idea as to what are the differences between the two processes. I have never expected answers to my posts but I think as there might be those wishing to put their hard earned (or otherwise) gelt into the company that Don is invested in they would like to know what the differences are. Personally I would give this one a long walk around until I knew if there were any substantial differences in what the two companies were doing. Silence on this point, does for me, speak volumes.

Crystal, I did respond to you that Petrobank and Habanero (notice the spelling) have no relationship and never have had one. I also told you that Habanero has never had an interest in THAI or CAPRI. You some how took this response as defensiveness. The fact is Crystal, I've never been motivated to look into Habanero as it is a penny stock. You say they have a similar process to THAI. I've looked through their web site and see only a brief mention of SAGD.

With further drilling there may be more than one potential SAGD oil sand pod on the property.

Perhaps you who have invested in this company could provide links to this process that Habanero has?


My appologies, In my mind I mixed SAGD with Heading Outs excellent article about underground coal gasification which looks very similar to the 'new method for producing oil' described in your article.


Underground coal gasification (UCG) experiments have been carried out in many coal mining countries and industrial scale production has been achieved in the former Soviet Union. More than 15Mt of coal has been gasified by UCG and in excess of 50 billion m3 of gas has been produced from UCG projects around the world. Despite research and many trials in different countries, no truly commercially viable UCG project has yet been demonstrated. However, various technologies are now available which could change this situation. A shallow seam, commercial power generation project is currently under development in Australia.

OK, Yet Another Thermal Recovery Process. Yawnsville.

Interesting use of well geometry, and it might be possible to economise further on well numbers with clever pattern design. This could well make someone some money in the right formation with the right fluids, if the oil price stays high (and if you don't have an opinion about that, you won't be reading this).

Heavy oil isn't really my field of expertise, but I can't see much of a business model in licensing this specific technique. There are just too many overlapping ways to slice and dice the parameters, and too many existing installations, for any imaginable patent strategy to get a meaningful lock on workable thermal EOR (if that's not an oxymoron).

I can think of a zillion things that could go wrong, mostly involving production well integrity and hydraulic isolation (i.e. how to avoid sucking nothing but gaseous combustion products once things break through at the toe). Formation stability in the flow zone might be another issue: shallow heavy oil sands tend to behave more like soils than rocks. But I'm sure there are ways to mitigate a lot of this, given time, experimentation, engineering and of course money.

This is evolutionary, not revolutionary. Good luck to them, though, as long as they don't start believing their own hype.

The oil sands industry has had too much hype - up to 315 billion barrels of reserves!

Western Canada is becoming an environmental disaster due to unregulated expansion of oil sands production.

Acid rain threatens Western Canada, government warned


Join the Sierra Club of Canada in our call for a moratorium on new developments in Alberta's tar sands


I wouldn't be surprised if government places an upper ceiling on oil sands production, say 1.5 mbd or 2 mbd, until all environmental impacts are addressed and fully understood.

Ace, plucky and HeIsSoFly
Thanks for your comments.
I wonder how many of the posters above were calling their brokers after reading this advertisement.
As if finding new ways of extracting oil is somehow a GOOD thing.
Every dime spent on crap like this does nothing to lessen our dependancy on FF one whit.

Hi Spaceman,

I've got a morally neutral stance on oil production. I see our situation as being analogous to late-stage alcoholism. As a species, we need to kick the habit, and Mother Nature is certainly going to help us with that, but if the faucet ran dry today, or if geopolitics turned it right off, there would be a disaster.

I love the intellectual puzzles involved in interpreting and controlling reservoir behavior. Of course the money I earn for tackling said puzzles comes in useful, and is very popular with the Plucky Underb*tch and the Plucky Underpuppies.



Whether it's a good or bad thing depends on how bad you think the oil crunch will be. If you think it will impose little more than a sizable economic cost and therefore an incentive to ditch oil for other forms of energy and more efficient practices, then this is likely a bad thing. If you think we're screwed without some more oil to power us through even the most aggressive possible transition, then it's a good thing.

oil crunch, climate change,runaway population, economic collapse.

If you think you can power your way through these four horsemen then more power to ya.

But if you get tired of debating the odds come on over to the dark side, for it's beginning to look like it's time for lifeboat drill:)


There is already alot of good discussion going on, so I make it brief :

In my view the good news about this technology are
- Apparently high recovery %
- low cost to implement
- doesn't require constant feed of water of natural gas

Some (possibly stupid) questions

Will the recovery rate neccecarily be fast? How will the 10% of burning loss be changed if we are to use low as possible air pressure and recovery speed? Many national oil companies might adopt conservation recovery practices and will not implement THAI IF it's not suitable for slow recovery. We need techniques that give good total extraction percentage but are suitable for slow recovery. Increased production would give completely wrong signal to the markets at this point.

Just my two cents.

Does anyone know what Hasbenaro Resources has done with their project using Thai or a very similar method. I first heard about it over a year ago. Field test were done and supposed to be released this spring or very early summer.I have not heard anything and can see no word on their site other than a referece to THAI,

Petrobank-- WHITESANDS

Has an estimated 1.6 billion barrels of bitumen in place. Recently completed an 87,750,000 dollar financing. Testing the THAI (tm) (Toe-to-Heel Air Injection) patented technology on this prospect that may revolutionize current oil sands recovery methods.

Does Habenaro have part or all of this? If this is the same project I heard of I am confused as to why I see no results for those test that were to be released this last spring.

I have a few hundred speculative shares in Habenaro that have lost 2/3 of their value since last year, so wonder if this new method is new or just a rehash of something that has so far failed. Maybe it's all part of the game and Habenaro has passed the ball to Petrobank... Companies win and Speculators lose.;)

Hi CrystalRadio, Petrobank has no relationship with Habanero Resources and never has. Habanero has never had any connection to THAI either.



Hi Don, Thanks, do you know what the process was that Habanaro was testing was called? It too involved 'fire in the hold'. Patents, I think, were held as well by Habenaro on it's method and it might be interesting to see what differences there were in the two procedures.

PBEGF.PK I looked up a quote $29.06/share for a stock listed on the pinksheets. The pinksheets are not reputable territory. Minimal hurdles have to be met to be listed on the pink sheets. I thought if it were a couple of dollars per share it might be worth buying a couple of hundred shares but at $29/share I want it listed on the Nasdaq or NYSE. Bob S.

They'll list there eventually, but overcoming millions of dollars in Sarbanes-Oxley expenses is a real barrier to smaller companies. Considering the state of the markets, perhaps your decision will work out for the better anyway.


Hi again Don,

I am luckily sitting on only 500 shares of Habenaro. I remember well the talk, when I bought them, about setting fire underground to use that rather than surface nat gas to separate sand from oil. If you know anything why that process seems to have gone by the boards let us know. I would be interested in investing in your THAI but not until I know what has happened with Habenaro's efforts. Thanks, sorry if this puts you on the spot but once burnt etc..:)

Could this technology be applied to depleted or depleting conventional oil wells or does it just relate to bituman/heavyoil? Sorry for my ignorance I'm not an oil guy.

Would the remaining TOIP in mothballed wells be recoverable with this technique or would the depth be a problem?

I am having problems appreciating how this technology could change the future supply picture. Presumably, even if this could be widely applied and supply large amounts of heavy oil, the refining capacity is mainly geared to, the soon to be scarce, light/medium oil? Or does this process 'upgrade' the oil to a lighter grade that current refining capacity could handle in a similar volume?

Hi mkwin, Greaves thinks THAI can work in many different reservoirs and even depleted wells. In fact, THAI was designed to work in the North Sea as a secondary extraction method. Heavy oil assts are plentiful on the planet so I think it could have an impact. How big and how fast that impact can be ramped up is the question. Yes, THAI upgrades the oil in situ but nowhere near WTI levels. Refiners will have no choice but to modify their operations so as to handle heavier grades of crude because the world is rapidly running out of the sweet, light grades.


In your opinion, if this was implemented in a large scale, is this a solution to peak oil or will it simply help to moderate the decline?

No, I don't think it's a solution to peak oil but I do feel it could make a significant impact on the downslope, especially in those countries that have large heavy oil assets. One of the advantages of the Canadian oil sands is that they are very large bit will not give up their oil easily or quickly. They therefore represent a long term buffer in a global decline of lighter oil. In other words, assuming THAI is viable, and society is able to dramatically reduce its fossil fuel use, critical elements of the economy such as rail transportation, agriculture and medical supplies will be able to be maintained. This scenario would provide a much better chance for society to transition into alternative power sources and a more sustainable way of living. That is my hope.