RE:RE:RE:Touchstone Why Invest - 4 Monetization of Assets Silly!@1explosiveGUY, you are going to have to do better in your technical analysis. Let me address some of your statements below:
1. Personally, I have seen wells produce at or even above their test rate. Well's clean up (there could be formation damage), production tubing and completions can be optimized (ESP's for example), water flows (which can overwhelm oil and gas flows) can be isolated and shut off, and last, but certainly not least, the testing equipment may not be optimal for the test. The point is that there are lots of variables that affect flow and only the operator has access to this information. So at best you are speculating.
2. I have seen no evidence which supports your decline rates, I'd be interested to see what actual evidence you have seen from the well.
3. You at least identify that the sands are marine. They are the Miocene Herrara sands which are deep water turbidites. I see no reference to them being "tight" or fractures as you seem to claim. In fact, from a brief literature search (DYOR) I found that the Herrera sands in the Penal oil field (approx 20km to the west) exhibit intergranular porosity, ranging from 12 to 40% and permeabilities ranging from 0.5 to 135 md. It's possible that the Penal oil field could be looked at as a possible analogue. Here is how Shell described it in 1958.
"Since 1936 the Penal oil field of Shell Trinidad, Ltd., situated in southern Trinidad, B.W.I., has been developed into a 6,500 b/d field producing both from a shallow pool and from deeper, Miocene Herrera sands at depths ranging from 4,000 to 10,000 feet. The Herrera has been proved productive from three superimposed tectonic levels, of which the intermediate one forms an overturned limb or an intricately built wedge. About 60 Herrera wells produce oil, condensate and/or gas; some of them came in with an initial production of more than 1,000 b/d, and five wells have reached a cumulative production of more than 1,000,000 barrels. The sands range in thickness from 50 to 300 feet in the overthrust, and are more than 800 feet thick in the second (intermediate) and third level (underthrust)"
From what I can see (and read) the 2nd test was of a light oil column underlain by a large aquifer. I don't think the test was long enough for coning to occur and it doesn't look like Touchstone tried to isolate any zones and so everything was comingled. A Production Logging Tool (PLT) run would have been able to determine what fluid was flowing and from where. I'm very interested to get the results of the next test to see how the top of the reservoir looks and to see what fluids the zone flows.
Just to remind you, this is what you wrote:
"production from Roy1 wouild not be as high as the test. when have you ever seen a well produce at the test rate? few of them. also you got to think of decline in any well. Maybe that well declines at 75% in year one. as they come off flush and virgin pressure oil wells do decline fast. not all , but these wells into marine sediment based sands, they come on strongest, its bcuzz the natural cracks are giving up their oil, like a fraced well. but natural fractures in these sands. the fractures drain but then producion shifts to what will flow thru tighter sands, and that is why this well might not be strong. then the water to handle, in the jungle too. that tells me it would take a much better production profile than this well to continue spending to bring it on".