(02-04-2016, 03:03 AM)ArtM72 Wrote: 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!