Triceratops-2 Summary

[petrengr1]

Here is a summary of what we know so far about Triceratops-2 as of July 6, 2012 along with a few comments and a little speculation. http://www.interoil.com/presentation/201..._Final.pdf 1. 9 5/8” casing was set at 4,111 feet (1,253 meters) 2. Top of the carbonate reservoir is at 4,482 feet (1,366 meters) http://www.interoil.com/newsrelease/2012...Update.pdf So, the top of reservoir is 371 feet below 9 5/8” casing shoe. 3. Bottom of the upper zone is at 4,869 feet (1,484 meters) Also top of hard streak. 4. Upper zone is really only from 4,482 feet to 4,869 feet (387 feet). 5. DST-8 tested the upper interval 4,111- 4,859 feet at 17.6 MMCFD with 13.6 - 16.3 Bbl/MMCF of condensate on a 48/64” choke with flowing surface pressure of 1,382 psig. See May 14th PR. 6. DST-9 tested the upper interval 4,111 - 4,859 feet at 28 MMCFD through a 56/64” choke. No mention of condensate rate or flowing surface pressure. See http://www.interoil.com/iocfiles/documen...inal-1.pdf chart 25. 7. Pressures from DST -7 indicate the upper reservoir is a gas/condensate reservoir and is in pressure communication with the reservoir at Bwata-1. http://www.interoil.com/iocfiles/documen..._Final.pdf chart 16. 8. Top of lower zone is at 5,133 feet (1,564 meters) Also bottom of hard streak. See May 14th PR. 9. The 264 foot (80.5 meter) hard streak separates the upper reservoir from the lower reservoir. See May 14th PR. 10. The gas water contact at Bwata-1 was expected at a drill depth of about 1,892 meters drill depth in Triceratops-2. http://www.interoil.com/iocfiles/documen...inal-1.pdf chart 23. However, Triceratops-2 DST-2 recovered water (we hope the water was mud filtrate and not formation water) and a small amount of condensate from the interval 1,938 - 1,967 meters. The top of this interval is 46 meters (151 feet) below the expected Bwata-1 gas/water contact so this is another indication that this is a different reservoir from Bwata-1. http://www.interoil.com/presentation/201..._Final.pdf charts 16 and 17. 11. DST#4 and DST#5 pressures are not on the water line indicating movable hydrocarbons, as associated with the wireline logs, core data and drilling data. Also chart 16. Neither the depth nor the pressure is given but it appears they are telling us the pressure gradient in the lower reservoir is somewhat less that a water gradient, indicating the presence of hydrocarbons in the reservoir. 12 The lower reservoir is from 5,133 feet (1,564 meters) to 6,660 feet (2,030 meters) or whatever the tests prove to be the bottom of the reservoir. This means the lower zone could be as thick as 1,527 feet. 13. The lower reservoir is in a different pressure system than the upper reservoir and the lower reservoir is thought to have higher pressure. Pressure information not yet public. 14. DST’s 1-6 were apparently in the lower reservoir while DST’s 7-9 were in the upper reservoir. I believe we have all the tests we will see from the upper reservoir. 15. While no information is yet publicly available I believe they have run and cemented 7” casing somewhere below the bottom of the hydrocarbon indicted zone at 6,660 feet (2030 meters) and cased hole testing is in progress on one or more of the zones in the lower reservoir. 16. The reservoir pressure of the lower reservoir has not been made available to the public but the reservoir apparently does not have sufficient pressure to flow a column of water or mud filtrate to the surface. The Company had previously said they were attempting to acquire a swabbing unit to lift fluid from the well and obtain a test of the lower reservoir. Obtaining a good test of the lower zone may be dependent upon their ability to swab a reasonably large volume of water or mud filtrate from the well in order to get a clear picture of the fluid contained by the reservoir. If the zone being tested is hydrocarbon bearing, the fluid being swabbed from the well should eventually change from water/mud filtrate to the reservoir fluid. If the reservoir fluid does not contain formation water I would expect the zone to begin to flow to the surface after recovering all of the mud filtrate. If the primary permeability is from fractures and the zone being tested is at or very near the hydrocarbon/water contact the well may begin to produce formation water soon after producing hydrocarbons. This may be what happen at Puri-1 which produced oil for about 10 days and went to water. This is not a problem for Triceratops-2 since the lower reservoir appears to be about 1,500 feet thick. We would just identify the hydrocarbon/water contact and move up the hole to produce the reservoir from a higher level.