Where is the Gas/Water Contact and the Elusive Western Fault?

[petrengr1]

Hession has said that the data from Antelope-4 ST-1 and Antelope-5 support the following:

1. The gas/water contact may be lower than previously thought.

2. The western fault is further west than previously thought.

In the absence of information on the subjects I will speculate a little.

The comment about the gas/water contact is probably based on better quality wire line logs, especially if they had better quality formation (higher porosity) at the depth of the gas/water contact. They have been using -2,214 TVDSS lately but GLJ had used -2,228 meters TVDSS.  I think the GLJ number is probably about where it should be. We have produced gas on a DST from a depth lower than -2,214 meters  TVDSS and perhaps lower than -2,228 meters TVDSS. Antelope-1 ST-1 DST #8 recovered 0.25 Bbl of  43.9 degrees API oil and 150 scf/day of gas from a depth of -2,193meters TVDSS to -2220 meters TVDSS.  Antelope-2 ST-2 DST #14 tested the interval -2,220 meters TVDSS to -2,252 meters TVDSS and recovered 1.4 MMCFD and 23.8 BPD of condensate (17 Bbl/MMCF). Also recovered 158 BWPD but it was thought to be load water and not formation water.

Now what was the basis of Hession saying that Antelope-5 supports moving the fault to the west? Please know that the following suggestions are highly speculative.

If we have a look at the map at   http://tinyurl.com/q2lzmbq page 13 you will see a post-drill map showing two faults to the west. The first fault is the earlier interpretation and is about 1.5 km west of Antelope-5. The most westerly fault shown on this map is the new interpretation and is about 3.7 km west of Antelope-5.

What additional information could they have to support moving this fault to the west? First they have the new gravity survey data shown on page 13. I believe the black line shown on the gravity graphic  is the same as the most westerly fault shown on the map.

I have said in the past that we need as many as three wells that have cut the fault in order to pin down the location of the fault. What I had not thought  of until recently is that some of the wells already drilled might have cut the fault. Remember they are using -2,214 meters TVDSS as the depth of the gas/water contact. Below I will list the TVDSS of the total depth reached on all of the Antelope wells:

Well Name           Total Depth meters TVDSS            Distance Drilled Below GWC

Antelope-1                     -2,515                                          302 meters (989 feet)

Antelope-2                     -2,323                                          109 meters (357 feet)

Antelope-3                     -2,483                                           269 meters (882 feet)

Antelope-4 ST-1             -2,248                                            34 meters (112 feet)

Antelope-5                      -2,307                                            93 meters (299 feet)

Antelope-6 (planned TD) -2,464                                         250 meters (820 feet)

Here is my speculation: Why did Antelope-5 support moving the fault west? I think they expected to cross the fault before striking the Gas Water Contact. Since Hession says Antelope-5 supports lowering the gas/water contact the well must have reached the gas/water contact before crossing the fault. They drilled another 299 feet below the gas/water contact. Did they cross the fault? I do not know but it is a possibility.

I believe it is also possible that Antelope-1 and Antelope-3 might have crossed the fault when drilling below the gas/water contact. If so they could have the fault located in three of the wells. I do not think Antelope-6 will reach the fault at the planned TD because the fault dips to the east and Antelope-6 is too far east to reach the fault at the planned TD.

Looking again at   http://tinyurl.com/q2lzmbq  page 13, if we take the distance from Antelope-5 to the most western fault shown on the map (3.7 km) and the Antelope TD of -2,307 we estimate the depth of the top of  the reservoir where the fault crosses at -1,500 meters TVDSS then the angle of the fault would be about 12 degrees. I think the fault angle could be anywhere between 10 and 20 degrees. If they have the data to prove the location of the fault is where they have drawn it on Page 13 we may be able to use that data and go to certification after Antelope-6 without drilling Antelope-7.

Just a lot of wild guesses with the information I can scrape up.

Have a good evening!!

[jft310]

Continuing the speculative idea a friend of mine speculates that Interoil may have chosen a different reservoir engineering firm for year end 2015 results . GLJ is not a SPA named reservoir engineering firm and for certification one of the 5 mentioned firms must be used . His guess is why not use one of those firms for year end results . His guess is Interoil may chose GCA for the year end 2015 report . Remember Oil Search and PAC LNG have chosen GCA and NSAI for their certification . Former management released year end reservoir results mid Feb so the window for year end results is mid Feb to the end of March .

[Relker]

Management stated that the new high case hypothese might increase the reservoir by 3 TCF. What do you think about the dolomite impact?

[ArtM72]

Pet -

Years ago IOC was being challenged by detractors claiming until long term flow testing was done any claims by IOC to a major find were just wishful thinking. At that time (knowing very little about anything) I was satisfied the GLJ group with their models based on seismics, aerial and well data had a pretty good handle on E/A size.

After the long term flow test was performed last year I thought, 'yeah, this gives us a definitive answer'. Instead, the answer was 'we need more drilling'. Now longer flow tests are running with the results presumably to be released in the next month or so. But as Antelope 6 approaches TD we continue to speculate about location of the western fault as an important consideration in likely reservoir size.

Is it the case that neither extended flow testing nor geologic monitoring is reasonably definitive and the results of one must be viewed in the context of the other to get closer to the truth? i.e. will the field appraisers end up taking an average of the geologic and flow models to reach their final estimates? Maybe a better question would be does either shed light on the characteristics of any water drive that might be present? How does one even measure or otherwise account for the existence and magnitude of a water drive before production?

Thank you so much for all you do and have done for this community.

[sageo]

Pet - Years ago IOC was being challenged by detractors claiming until long term flow testing was done any claims by IOC to a major find were just wishful thinking. At that time (knowing very little about anything) I was satisfied the GLJ group with their models based on seismics, aerial and well data had a pretty good handle on E/A size. After the long term flow test was performed last year I thought, 'yeah, this gives us a definitive answer'. Instead, the answer was 'we need more drilling'. Now longer flow tests are running with the results presumably to be released in the next month or so. But as Antelope 6 approaches TD we continue to speculate about location of the western fault as an important consideration in likely reservoir size. Is it the case that neither extended flow testing nor geologic monitoring is reasonably definitive and the results of one must be viewed in the context of the other to get closer to the truth? i.e. will the field appraisers end up taking an average of the geologic and flow models to reach their final estimates? Maybe a better question would be does either shed light on the characteristics of any water drive that might be present? How does one even measure or otherwise account for the existence and magnitude of a water drive before production? Thank you so much for all you do and have done for this community.

Art- My "dittos" for your thanks to Pet !!!" border="0" class="smilie" src="http://shareholdersunite.com/mybb/images/smilies/smile.gif" />

[petrengr1]

[quote='Relker' pid='66440' dateline='1454518541'] Management stated that the new high case hypothese might increase the reservoir by 3 TCF. What do you think about the dolomite impact? [/quote

Relker- Here are a couple of quotes from the Nov. 13, 2015 presentation http://tinyurl.com/hdce75h page 17

1. “Potential 1-3 Tcfe upside identified in western flank – JV considering further appraisal”

2. “Potential 1-3 Tcfe upside identified in western flank – JV considering further appraisal

An additional appraisal well could add 1 – 3 Tcfe and enhance our certification payment by $400 million to $1.2 billion.”

As you know the dolomite is of paramount importance. The further it extends to the west (or any direction) the better for IOC. If we look at http://tinyurl.com/palye9e page 13 we can see the new (most westerly) fault on the map to the left. This fault trace seems to be the same as the black line on the gravity graphic to the right. The black line seems to include the bright red area which could be the reef. On this map the fault is moved about 2 km west of the fault of the previous interpretation. (directly west of Antelope-5)

Now let’s have a look at the latest presentation http://tinyurl.com/z4yzgue ;

page 14. Now the newly interpreted fault (most westerly) has taken on a completely different shape and it is now only moved 1 km west from the previous interpretation. (directly west of Antelope-5)

I guess it is pretty absurd for me to try to guess how far the dolomite might extend to the west when even IOC can’t make up their mind where the fault is.

[sageo]

[quote='Relker' pid='66440' dateline='1454518541'] Management stated that the new high case hypothese might increase the reservoir by 3 TCF. What do you think about the dolomite impact? [/quote

Relker- Here are a couple of quotes from the Nov. 13, 2015 presentation http://tinyurl.com/hdce75h page 17

1. “Potential 1-3 Tcfe upside identified in western flank – JV considering further appraisal”

2. “Potential 1-3 Tcfe upside identified in western flank – JV considering further appraisal

An additional appraisal well could add 1 – 3 Tcfe and enhance our certification payment by $400 million to $1.2 billion.”

As you know the dolomite is of paramount importance. The further it extends to the west (or any direction) the better for IOC. If we look at http://tinyurl.com/palye9e page 13 we can see the new (most westerly) fault on the map to the left. This fault trace seems to be the same as the black line on the gravity graphic to the right. The black line seems to include the bright red area which could be the reef. On this map the fault is moved about 2 km west of the fault of the previous interpretation. (directly west of Antelope-5)

Now let’s have a look at the latest presentation http://tinyurl.com/z4yzgue ;

page 14. Now the newly interpreted fault (most westerly) has taken on a completely different shape and it is now only moved 1 km west from the previous interpretation. (directly west of Antelope-5)

I guess it is pretty absurd for me to try to guess how far the dolomite might extend to the west when even IOC can’t make up their mind where the fault is.

Pet-Thanks for your response to Relker . At times,I still wonder that with all of the quality minds we have at work and all of the advanced technology available and all of the money spent,we still don't know just how huge this field really is. Truly mind - boggliny sometimes . True, the crude price drop a factor,but still seems strange. Will be nice if Ant 6 gives us some good news . Best to you.

[jft310]

Well Hession negotiated 2 runs at the money (certifications) with reason . Comes down to Interoil selecting one of the specified 5 appraisers that best represents their view and Total doing the same . We get paid on the average . A friend stated if we don't get 10 T's on round one we will get it on round two . A leading indicator will be the year end 2015 asset size given out by the company next 2-6 weeks out from here . Hopefully we get the full report not just the number .

[petrengr1]

Pet - Years ago IOC was being challenged by detractors claiming until long term flow testing was done any claims by IOC to a major find were just wishful thinking. At that time (knowing very little about anything) I was satisfied the GLJ group with their models based on seismics, aerial and well data had a pretty good handle on E/A size. After the long term flow test was performed last year I thought, 'yeah, this gives us a definitive answer'. Instead, the answer was 'we need more drilling'. Now longer flow tests are running with the results presumably to be released in the next month or so. But as Antelope 6 approaches TD we continue to speculate about location of the western fault as an important consideration in likely reservoir size. Is it the case that neither extended flow testing nor geologic monitoring is reasonably definitive and the results of one must be viewed in the context of the other to get closer to the truth? i.e. will the field appraisers end up taking an average of the geologic and flow models to reach their final estimates? Maybe a better question would be does either shed light on the characteristics of any water drive that might be present? How does one even measure or otherwise account for the existence and magnitude of a water drive before production? Thank you so much for all you do and have done for this community.

Art- I am not qualified to answer your questions. I have very little experience in evaluating the size of newly discovered reservoirs such as Antelope. Most of my experience regarding determining reserves had to do with reservoirs that had been on production for a long time. So I will just give you some of my usual ramblings.

I think our long ago detractors who wanted long term flow tests expected (or wanted others to expect) that the reservoir would be substantially depleted or suffer a very large pressure drop if a long term flow test was done. So they likely had an agenda hoping to see the price per share fall.

As I have said before I do not think a pressure drop of 0.06 to 0.08 psi is sufficient to draw any viable conclusions. I do not consider the three day test that was done last year to be a long term test. I would not even consider the present +/- 15 day test to be a long term test. The more gas that is produced from the reservoir the better this method is for determining the resource volume. These relatively small volumes, as compared to the reservoir volume, and these extremely small pressure drops as compared to the reservoir pressure give us some idea of the reservoir size  but I would not say they should be used as the final answer for the reservoir volume. If we have no water drive this method will be the most accurate way to determine the reservoir volume after a substantial amount of the gas has been produced, say 20%.  We are trying to do it by producing about 0.00152% of the reservoir volume with a pressure loss of about 0.0017% of the reservoir pressure. I do not think that is very accurate even if all of the measurements are perfect.

Determining the reservoir volume using seismic data, gravity data and well data is not much better. As we have seen the seismic is not too good. The wells we drill frequently come in several hundred feet high or several hundred feet low. They can not tell where the western fault is. They certainly cannot tell us if this formation contains gas or oil or what the porosity is at any level. For estimating reserves this is a very imprecise tool. It is more for the “big picture”. As for well data again it is not precise as far as the overall reservoir is concerned. Core analyses gives us the porosity of a small sample but it is hard to extrapolate that to the whole reservoir. The logs are not precise either. We have had problems finding the gas/water contact using logs mainly due to the low porosity limestone where we have found the gas/water contact. They have even had trouble identifying what is productive and what is non-productive. At Triceratops-2 we thought we had several hundred feet more productive rock based on the logs but it turn out to be filled with water. We have to use the logs to determine the porosity of the gross intervals since it is not practical to core the whole well. We have good porosity, medium porosity, low porosity and no porosity. We have to use the logs to determine how many feet of the gross productive interval is productive and how much is non-productive, call the gross to net number. We have to use this data to come up with an average porosity number for each of the main sections of the reservoir i.e. High porosity limestone, high porosity dolomite, low porosity limestone and how much is nonproductive. We get this data for each well and then try to apply these numbers to the whole reservoir. As you can see none of this stuff is precise but it is the best tools we have so that is what we use.

Unfortunately we will not know the recoverable gas volume until the reservoir is depleted and the wells plugged and abandoned. We will never know a precise number for the original gas in place because after the field is abandoned we will still be “estimating” how much gas remains in the reservoir upon abandonment.

So, yes the engineers that do the reserve determination will use all of  the data available. Seismic, gravity, logs, cores, flow tests etc. I would not say they will “average” the methods but that they will give what they consider to be the proper weight to each technique in determining their final number. I guess this is why there is such a wide spread between the companies that have given previous estimates. About the only good news that I can think of is that most of the data obtained since GLJ gave their first estimate in 2009 has been positive.  Wells have mostly come in higher than anticipate making the reservoir thicker. The good porosity rock has been better than expected in the last two wells, Antelope-4 ST-1 and Antelope-5. Antelope-3 was also a great well that was drilled since 2009. Now they think the western fault is further to the west making the area of the field larger. The results from Antelope-4 and Antelope-5 indicated that the gas/water contact may be lower than presently being used. The flow tests at Antelope-5 have shown how great the deliverability is with 60+ MMCFD and a drawdown of only 2 psi. And of course the minimum reservoir pressure loss (0.06 - 0.08 psi) during the first flow test which produced 152.9 MMCF is a positive indication. One would think the present resource number should be larger than GLJ got in 2009 before they got all of this additional positive data.

Regarding the possibility of the presence or absence of a water drive, no the seismic data or gravity data are not going to help in that determination. The main reason GLJ thinks there is no water drive is because the Antelope aquifer is slightly over pressured as compared to the regional aquifer. That means that the water in this reservoir is trapped in a sealed compartment  so the regional aquifer can not feed water into the reservoir as the gas in produced. As a general rule a water drive will try to maintain the reservoir pressure depending on how fast the gas is produced. In a water drive field we see the lower wells going to water indicating that the water is moving into the reservoir. Also sometime the water will flow through the higher permeability zones and/or fractures to the up dip wells. This leaves some of the gas behind in the lower porosity zones so a water drive is a less efficient depletion system than a straight pressure depletion drive. Of course sometimes we have both.

I hope that answers some of your questions even though I am not qualified to give you an answer as to how the “resource calculators” will  actually do their work.

Have a good evening!

[Relker]

If IOC does not have a clear picture of the field size, this will be troublesome for the appraisers as well. This might lead to big differences between the numbers during the coming weeks. If this will be the case, parties will be more inclined to do A7. May be IOC and Total made an arrangement in the transitional agreement about such event. After all IOC was not obliged to hand over operatorship before the large license payment.