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.

[ValueSleuth]

petrengr1,

Thanks for your very informative summary that places all the data available in a form that we all can easily absorb.

Needless to say, the lower reservoir results are eagerly anticipated.

VS

[Palm]

Thanks Pet! Really lays things out for us laymen. The liquids we know from Wayne at the AGM are "clear", meaning condensates. He also stated when asked about the pressures, "We are not as concerned because it's easy to move liquids, not easy to move gas." Can't wait to hear what it is that moves. Tree is apt to pipe in with George Castanza's famous line.

[Ass0ciatedPress]

A very well thought out and dictated summary of the IOC well we are all keeping a close eye on. Thank you pet, excellence as usual.

[Thylacine-2]

Thanks Pet!
Assume there is commercial light oil/condensate at T-2.

Would it be feasible, with the same well, to produce from the lower reservoir and re-inject separated associated gas into the upper reservoir?

[petrengr1]

Thylacine-2 I really think it is a little premature to even discuss such an eventuality. We have very little information about this reservoir and there are many things here that I do not yet understand. IOC has led us to think the formation might contain liquids or liquid rich gas. I have never seen a reservoir filled with condensate. Condensate usually forms when the temperature and pressure of a gas phase is reduced when the gas is produced from a gas reservoir. So in a gas reservoir the hydrocarbons are in the gas phase not the liquid phase. In a normal gas reservoir the condensate condenses out of the gas phase during the production process and we get gas and liquids at the surface where we separate and measure both. We can then say how many barrels/MMCF we have at surface conditions.

Sometimes we have retrograde condensate reservoirs. These reservoirs are usually higher temperature and pressure reservoirs. I would think a retrograde reservoir would have a higher temperature and pressure than Triceratops. In the case of retrograde condensate reservoirs, as the pressure is reduced by production, liquids condense out in the reservoir. Most of these liquids coat the reservoir rock and are never produced as liquids at the surface. http://www.glossary.oilfield.slb.com/Dis...cfm?ID=611

Now, does the Triceratops Field have liquids in the reservoir rock? I do not know. If we do find producible liquid hydrocarbons in the reservoir rock I think we may have to call it an oil zone instead of a gas or gas condensate zone.

Now to your question. The hole size of this well across the reservoir is now 7” casing. This is getting a little small for dual completions in the same hole. When we add to that the fact that the oil zone may not flow to the surface without artificial lift it might become a little more complicated. I think if IOC ever discovers an oil zone in the Triceratops or Elk/Antelope Fields the best method of artificial lift will be “gas lift”. So we would use either the gas from the oil zone or the gas zone to lift the liquids to the surface. We would have to have a small compressor for one well but this type operation would not require well service as often as other types of lift i.e. rod pumps or electric submersible. This might be important in the jungle where there are no well service units or roads. If we have to artificially lift the fluid from the well the annular space in the well bore will not be available to use for injection.

If we find an oil zone the government might allow the gas to be flared until a gas line is installed as the gas volume to be flared would be much smaller than would be the case with a gas condensate reservoir. Plus some of the gas could be consumed as compressor fuel for the gas lift compressor.

The long and the short of it is, let’s not count our eggs until we see the tests from the lower reservoir. I do not expect to see any commercial liquid hydrocarbon production from this well in the short term.

[Spartina]

Once again thanks pet for your continued expertise and efforts. Perhaps a silly question but can we officially say that T2 is a reef yet? Tia.

[petrengr1]

Spartina- A very good question. Instead of me answering let me refer you to a quote from the last PR and a statement by Phil:
"We believe that the pressure data, flow rates recovered from the DSTs and well logs demonstrate a high quality porous reservoir," stated Mr. Phil Mulacek, Chief Executive Officer of InterOil. "We are pleased to find that our aero-magnetic and gravity data utilized in combination with modern seismic data has yielded our second significant discovery of hydrocarbons in a reefal reservoir in Papua New Guinea. Our forward plan to obtain definitive test results from the lower reservoir section is to set casing over the entire reservoir interval and perforate zones of interest."
http://www.interoil.com/newsrelease/2012..._Final.pdf

Now it can’t be any more clear than that can it? He says it is a “reefal reservoir”. Now the next question. Can it be reefal without being a reef?

Before you asked the question I had always assumed that Triceratops-2 was drilled on a reef. I visualize a reef as being a buildup on a limestone platform. So the reef should be thicker than the surrounding limestone platform. If we look at all of the diagrams presented by IOC such as http://www.interoil.com/presentation/201..._Final.pdf pages 6 & 7 it appears that the seismic indicates several “mounds” around the area. So it looks like we should have reefs.

I am beginning to think the geology here is more complicated than we first believed. Of course nothing is ever as simple as it seems. After looking more carefully at the data, or more specifically comments, IOC has presented I am more inclined to think Triceratops-2 may not be on the “main” reef. We have several hints that Triceratops-2 may not be the “original” or primary reef:

1. http://www.interoil.com/presentation/201..._Final.pdf page 13. “Reef development can only be confirmed by well logs and cores.” (Phil’s comment above was after they had the logs and cores.)
2. “Rock cuttings, believed consistent with the wells off flank position, appear to be mainly detrital and finer grained than the Antelope-1 and Antelope-2 wells.” This sounds like the cuttings indicate the well is on the flank of a reef. “Detrial” means they are seeing rock that has been eroded off of another primary source and re-deposited and cemented at a different location than the original source. This sounds like we are drilling on the flank of a reef that has been eroded and re-deposited.
3. The reef at Antelope has dolomite in layers. The dolomite at Triceratops is distributed throughout the section. I believe this is what you might expect if a nearby reef with layers of dolomite and limestone was eroded off and re-deposited it would be found distributed throughout the section at the new location and would not be found in layers like the original source.
3. The porosity is lower than we expected if we were drilling a true “original” reef.
4. The texture of the rock is finer grained than the reef at Antelope.
5. There is a thick layer of marl in the middle of the section at Triceratops.
6. There are two pressure systems or two separate reservoirs. This does not sound like one big reef.
7. The lower reservoir appears to be separated from the reservoir at Bwata-1. So how is it separated? Is it a fault or some geological phenomenon like a pinch out or a separation by some impermeable limestone barrier (compartmentalization)?

So, what does it all mean? It is like the joke about the pony. With all of this evidence there must be a pony around here somewhere.

The good news about all of this:
1. Phil says it is “a reefal reservoir”.
2. Whatever it is we know it has some porosity and permeability and is capable of producing gas at a rate of at least 28 MMCFD.
3. It is fairly thick, maybe up to 2,200 feet. (Waiting on tests at the bottom for confirmation.)
4. Seismic indicates mounding in the area that might be reefs.
5. Seismic indicates a mound up dip from Triceratops-2 which may be the primary reef or source of the rock we drilled through at Triceratops-2.
6. It appears that we may not have to have a “primary” reef in order to have substantial reservoir rock containing significant gas reserves.
7. Even if all of the rock at Triceratops Field is the same as Triceratops-2 it will be a great discovery.
8. If we find some “primary” reefs the porosity and permeability will be better than Triceratops-2.
9. These eroded and re-deposited reefs make acceptable reservoir rock. This may have good implications for all of the prospects we have around the Antelope reef.. Mule Deer, Deer, Raptor Duckbill, Mountain Lion, White Tail, Grizzly etc. http://www.interoil.com/presentation/201...inal-1.pdf page 21 (magnify to 400%) Eroded and re-deposited reef may be better than fractured limestone only. If we have this type of rock at other locations all we need is a seal and a trap. In this hydrocarbon province, if we have reservoir rock, a seal and a trap it will probably contain either gas or oil or both.
10. There are millions of acres of this limestone platform. There is no reason why we should not find more reefs. Some may be primary and some may have been eroded and re-deposited. We prefer the primary reefs but we can live with the eroded and re-deposited rock if that is what we find.

I have no inside information. All of the above is just speculation on my part, so take it all with a grain of salt or if you prefer, just read the first paragraph and let go at that.

[petrengr1]

I asked Wayne several questions back on June 18 about the missing details of the technical data. About all I got out of him was a promise to give us a thorough technical update on Triceratops-2 after they complete the testing of the lower zone.
They have told us that the lower zone has a different pressure than the upper zone. I have interpreted that to mean that it has a higher pressure but we do not have the pressures (numbers) to back that up. The lower zone is about 1,500 feet thick if they are able to prove producible hydrocarbons all the way down to 2,030 meters. If this proves to be correct the larger percentage of the pay will be in the lower zone where we have higher pressure.

The testing of the lower zone should prove (or disprove) if there are producible hydrocarbons below the Bwata-1 gas/water contact which was expected to be at a drill depth of 1,892 meters in Triceratops-2. If it is true that we have producible hydrocarbons all the way down to 2,030 meters that will lower the gas/water or oil/water contact by 138 meters (453 feet). If you look at http://www.interoil.com/presentation/201...inal-1.pdf chart 24 this would move the gas water contact (red dotted line) to the northeast, making the area of the field larger and increasing the height of the gas/hydrocarbon column from 5,500 feet to 5,950 feet.

The most important question that I asked Wayne is: Can we see the 80 meter hard streak that separates the upper and lower reservoirs on the seismic and, if so, do they think this higher pressure reservoir and lower hydrocarbon/water contact applies to all of the field to the north and west. If this turns out to be true we will have two reservoirs throughout the field with the more shallow reservoir having lower pressure than the deeper reservoir. Since we got the sample of clear condensate at 1,938 - 1,967 meters drill depth at Triceratops-2 I am pretty sure the lower zone will be a gas reservoir in the up dip parts of the field to the north and west. That could mean that the largest percentage of the field (below the hard streak) will have a lower than expected hydrocarbon/water contact and a higher than expected reservoir pressure. Both of these parameters will add significantly to the Triceratops Field reserves. We await the results of the testing of the lower zone and the thorough technical update to follow.

[admin]

Very, very thorough, Pet, thanks for it all.