'ArtM72' pid='16531' datel Wrote:Pet - Thanks as always for your insight. A couple of basic question if you don't mind. First, is it correct to assume that the formation draw off is most likely to be from near the bottom of the wells given there is where the highest condensate fraction is seen, with higher areas only opened up only as necessary to keep the LNG plant running at capacity? Next, I haven't seen anything that suggests testing will be done to record how flow tests at any E/A well influence the static pressures seen at the others. I would think this to be an important test. Have I missed something along the way? Best regards,
Art- Remember this is just one man’s opinion.
1. I believe that the most important thing in the operation of this field will be to keep the LNG plant fully loaded. In order to do this I think they will want all of these wells to be capable of producing in excess of 100 MMCFD. So far the bottom of the zone where IOC suggests the liquid content is higher has been low porosity and permeability and will not be capable of producing at the desired rates. It is possible that they could drill a horizontal hole in the bottom of the reservoir and get the desired volume but I do not think IOC or the new operator will do that. Another problem with doing this is that the producing zone would be near the gas/water contact and the producing well would begin to produce water soon after beginning production. Their main interest will be to have a smooth running operation with no worry about having enough gas to load the LNG plant. GLJ has said they do not see that much difference in the liquid content of the gas with depth.
2. Regarding the recording of reservoir pressure (bottom hole pressure) in offset wells while testing a new well, this would seem like a good idea but it may not be so easy to accomplish. In fact it sounds like such a good idea that I suggested it to the highest level of this Company in an email dated 1/31/2009. This was prior to the testing of Antelope-1. I did not receive nor did I expect an answer.
There are many things that we do not know that would come in to play here. For example this technique of trying to prove reservoir continuity would probably work much better in Texas where you might have one relatively thin zone with good porosity and permeability and a much closer well spacing.
I now know that Elk-1 is in a different fault block so it would not have been appropriate to put a pressure recorder there to check continuity with Antelope-1. I am not aware of how Elk-4 was left when operations were suspended but my guess is that the producing zone was plugged off for safety purposes.
I believe most of these wells are plugged off down hole for safety purposes when operations are suspended so it is not possible to record the reservoir pressure at the other locations.
For this to be successful in such a large reservoir with the wide well spacing in a relatively low porosity reservoir it would probably be necessary to flow the well for an extended period and both wells would need to be completed in the same zone of the reservoir. For example in Antelope-1 the massive gas reservoir is now sealed off behind pipe and only a very thin zone at the bottom was left open with the intent of making a long term test to see if they could prove the presence of oil or high liquid content gas in this very tight zone at the bottom of the reservoir. As far as I know the test was never done. With Antelope-1 only open in the lower tight zone I doubt that such a pressure test would be successful. Antelope-2 was temporarily plugged down hole when operations were suspended. In any case the massive gas zone was sealed off behind pipe in order to do the horizontal drilling.
So we will not be seeing any pressure readings from offset wells while testing Antelope-3.