199 comments on Extracting Heavy Oil: Using Toe to Heel Air Injection (THAI)
Comments can no longer be added to this story.
User login
Archives
License
This work is licensed under a Creative Commons Attribution-Share Alike 3.0 United States License.
GAIA Host Collective
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