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