Extracting Heavy Oil: Using Toe to Heel Air Injection (THAI)
Posted by Gail the Actuary on August 27, 2007 - 10:00am in The Oil Drum: Canada
Topic: Supply/Production
Tags: heavy oil, oil, tar sands, thai [list all tags]
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:
http://www.petrobank.com/webdocs/whitesands/whitesands_application.pdf
http://www.petrobank.com/webdocs/whitesands/whitesands_eub_response.pdf
http://www.nt.ntnu.no/users/skoge/prost/proceedings/aiche-2004/pdffiles/...
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.
http://science.reddit.com/info/2j4o1/comments
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?
Alberta
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
Texas
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.
Don
1observer,
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
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.
http://www.petrobank.com/hea-faq.html
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.
Don
Don
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.
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.
Don
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
CORRECTED ECONOMICS FIGURES
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
ALBERTA THAI PROJECT
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
expenses
royalties
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.
http://www.sproule.com/prices/hvyoil_history.htm
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.
Don
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.
FF
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.
This is Don's original description of the situation. Perhaps it makes the situation more clear:
"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.
FF
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.
FF
Fractional_Flow,
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! :-)
RC
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.
RobertInKyoto
I haven`t escaped from reality. i have a daypass.
Roger,
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.
http://www.petrobank.com/hea-faq.html
Don
(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.
Don