What should we expect at Antelope-3 and Elk-3? Based on http://www.interoil.com/iocfiles/documen...Final_.pdf charts 10 & 11 I would expect Antelope-3 to be slightly down dip from or flat with Antelope-1 and considerably up dip from Antelope-2.(Looking at the maps in the GLJ report I would say the top of the formation in Antelope-3 will come in at the same depth as Antelope-1 or about -1550 meters sub sea) I think Henry’s 13 TCF number may be referring to gas in place instead of recoverable gas. GLJ’s “high estimate” for original gas in place was 12.54 TCF.
Gaffney and Cline (GCA) was not the first one to mention that the gas resource would increase with more wells being drilled. Their report came out in Jan. 2012. On Feb. 16, 2010 I suggested that this might be the case http://finance.yahoo.com/mbview/threadview/?m=ts&bn=26290&tid=158553&mid=158823&tof=26&rt=2&frt=2&off=1 At that time we had not received the GLJ report for the end on 2009 which was dated February 17, 2010. So with Elk-4 and Antelope-1 drilled, GLJ had estimated recoverable gas of 3.8 TCFe. When the report for 2010 which included the drilling of the upper part of Antelope-2, GLJ had an estimated recoverable gas volume of 9.1 TCFe but this included all of Antelope, Elk and Mule Deer. When the report of 2011 came out they dropped Mule Deer but included the lower part of Antelope-2, including the horizontal drilling, and increase the recoverable gas volume for Elk/Antelope to 9.4 TCFe.
The GCA report of January, 2012 estimated a best case for recovery of raw gas at 6.5 TCFe and suggested that the resource volume would increase with the drilling of more wells. (I have not seen the part of the report that says that.) The GCA number for original gas in place for the “high case” is 12.1 TCFe. So there is not much difference between the GCA “high case” original gas in place (12.1 TCFe) and the GLJ “high case” original gas in place (12.54 TCFe). This leads me to think there is not much difference between the two companies about gross rock volume, porosity and water saturation, so the difference must be in the recovery factor i.e. how much of the gas does each company think is recoverable. I do not think GLJ ever thought the gas could be recovered from the three existing wells, so they would also expect to see more wells in order to recover their estimated 9.4 TCFe. GLJ thinks the reservoir will be depleted as a “pressure depletion” drive based on the reservoir pressure being above the regional aquifer pressure. This tells them that this is a closed system. If GCA thinks the reservoir will have a water drive type depletion this could be why they think the recovery factor will be lower. Or possibly GCA wants more wells to confirm there is no compartmentalization. If the reservoir proves to be somewhat compartmentalized then each compartment will have to have a well in order to recover the gas or perhaps a horizontal hole could open several compartments. This logic seems to work for the “high case” (P-10) since the estimates of gas originally in place are fairly close but it does not work for the “best case” (P-50) and the “low case” (P-90) because the GCA numbers are much lower than GLJ. I do not have the technical part of the GCA report so I can not determine why there is so much variation between the numbers.
In any case several more wells will be required to recover 9.4 TCFe in a reasonable amount of time. Much of the value of the gas lies in being able to recover the gas as soon as possible. If we want to load an 8 mtpa plant we must be able to produce 1,120 MMCFD. Each well should be able to produce ~ 100 MMCFD so we will need 10 or 11 wells and probably more in order to have redundancy to make sure we have sufficient capacity in the field to keep the LNG plant loaded. (Talisman produces up to 200 MCFD from some wells in South Sumatra with two large flowlines off of the well head, so this is another possibility since our wells will be capable of flow rates of more than 200 MMCFD) If we produce 1,120 MMCFD we will recover 0.408 TCF/year, so we can recover 9.4 TCF in about 23 years.
I guess all of the above is to tell you what I don’t expect i.e. since both companies have a high case original gas in place of a little more than 12 TCF I do not think we should expect additional drilling to bring the estimated recoverable gas to 13 TCF. I do expect the GCA “best case” (P-50) number of 6.6 TCF to increase with more drilling and approach the GLJ “best case” number of 9.4 TCF.
More specifically what do I expect at Antelope-3 and Elk-3?
As I mentioned above I think Antelope-3 will find the top of the Puri limestone reservoir at about -1550 meters sub sea or at about the same depth as Antelope-1. So, I expect Antelope-3 to have the same amount of gas column as Antelope-1 or about 2,225 feet of gas column. The good news is I believe we will have a log that looks more like Antelope-2 than Antelope-1. The GLJ maps indicate that we should see the high porosity limestone above the dolomite again like we did in Antelope-2. See http://www.interoil.com/presentation/201...Final_.pdf chart 12. Every time we drill we find something new and unexpected but right now I expect the top of the zone at Antelope-3 to look similar to Antelope-2 which is much better than Antelope-1. So, I think we will have the thick gas column of Antelope-1 and the better rock quality of Antelope-2. Based on the GLJ maps Antelope-2 had a gas column height of 1,782 feet or 443 feet less than Antelope-1 because it is down dip. This should mean that Antelope-3 will be the best well of the three.
Elk-3 should hit the top of the Puri limestone at about -1,700 or -1,800 meters sub sea depending on whether you use the GLJ interpretation or the IOC interpretation. Let’s go with -1,750 meters sub sea. I can not give drill depths until I have the derrick elevation. With the -1,750 meter sub sea estimated formation top I expect the well to have a gas column height of 1,634 feet. The maps look like we could have drilled a higher location if the well was positioned a little further to the south. With only Elk-1 and Elk-2 in the Elk Block I would have to expect fractured limestone only in Elk-3. If we find a little reefal porosity I will be happy to be proven wrong.
After doing a little more research to answer a question in a "Triceratops string" I wrote the following which I am moving here where it belongs since it is about Elk-3:
Elk-2 hit the top of the limestone at -2262 meters sub sea. The gas/water contact is at -2248 meters sub sea. I expect Elk-3 to hit the top of the limestone at about -1750 meters sub sea or roughly 500 meters higher than the gas/water contact.
The top 500 meters of rock at Elk-2 had about 103 meters of pay i.e. 2% porosity or better. The average porosity of this 103 meters of reservoir rock was 7.4% (6.6% in-situ). I am hoping to find some porosity better than this at Elk-3 but if that does not pan out we should have at least 100 meters (328 feet) of net reservoir rock in the 500 meters (1,640 feet) of fractured limestone that we drill above the gas/water contact.
We should make a good high volume gas well and prove that we do have at least some matrix porosity in the Main Elk Fault Block. Perhaps this will be good enough to get GLJ to add a little to the resource volume.
