Member Info for mbarnholdt

Timing of the oil wells would be great, given the direction of prices as of late.

Was my next question MJ, have they let the contracts and who is fabricating?

Yes I missed that the first time I read this. Sounds like they are going to convert an older producing well to injection service. Be interesting step forward on the legacy operations.

Thanks so much for this Adon, most helpful. Sure hope we can get a few of those in the 175 b/d range.

I wondered about that also Matt. I'm sort of with MJ, in that in a country in which more gas is needed for local plants (employment) and LNG esport gas is needed, that there isn't more urgency. I came up in U.S. Shell where it was go go go, but also worked West Africa for awhile, so I know that life moves much more slowly in some places. I've also worried that unless we get some new revenue sources, our cash will dwindle away, or another raise will be needed. My recollection is that the last one was at 2.20 u.s. or thereabouts. I think my focus would be on making the wall of cash start happening. If Coho and Cascadura aren't ready by the time the first 4 wells are complete, keep going on the 200+ legacy locations I have heard quoted before.

Good news, thanks for sharing that.

I think I am with Matt on this one. Coho has put into question how quickly can gas be brought to market both here and at Cascadura. Would also provide something like 750K or so per month at 10 mmcf/d. Not sure how fired up I am to drill Coho development well until I see first production there. If still not producing after well sequence on legacy, I think I'd go ahead keep drilling legacy until it is online or at least a clear path toward getting there.

ah thank you matt, figured i was missing something obvious

Been sort of wondering why the need to go through the Shell plant at all. Thought Coho stream was pretty dry gas. Did I miss something?

Appreciate it as always Scott.

They really haven't said much (or I missed it) about the four legacy wells, whether they have spud, what expectation might be (talking 10 b/d, 100 b/d?). Anyone have more information on?

I also had hoped that between Heritage and the new Minister that a fire would get lit under someones butt, Shell, NGC, whomever the hold up is on Coho. This long for a 2km connection really is eating at me.

I can see why they would have used a heavier fluid at Chinook. The Herrera group seems to be a bit of a tricky drill with lots of kicks, and other bad experiences on some of the older Shell wells.

I also would have thought the probability of success would be higher for Royston, particularly since it was known to be charged and logged. But I once funded a portion of an exploration well with an 80% probability of success where it turned out the sand wasn't there. Well suspended even before reached TD. Just about the time you think you have things figured out, something bites you in the tail (Chinook). Ideal result for Royston I think would be high pressure flow test with lots of condensate, no water or impurities, and sand continuous throughout the whole structure shown by later development wells. I pray to the Petroleum Gods every day.

Thats a lot of rock volume. I used .18 porosity, gas saturation of 50% (arb), and had to guess on FVF since couldn't find a table correlating an empirical FVF with depth. Used 80% WI and 60% recovery factor and come up with recoverable TXP of about 1.3 TCF. This assumes that the geology/fluids are consistent over the entire structure which would only be supportable with more wells. Well tests and fluid samples will give us more-I would think they will install a downhole psi gauge here too which would be helpful. Since the well is hc rich at TD, that would be lowest known for now-might actually be some more sand which was how i interpreted. If we can get good flow test, would assume GLJ would allow this well and one offset as proved developed/undeveloped. I'm sure there are some big holes in the foregoing, would appreciate comments from all.

Thanks Scott, for your always well though out and informative posts. I appreciate the update also on Western Canada, I did some work on early Montney way back when. They have struggled for quite awhile.

Right now I'd be happy with the $2.50 or thereabouts if it meant Coho was producing into sales. One would think that if world gas prices are rising, that getting this relatively cheap gas to market would be advantageous to NGC.

Well done. Someone who knows a thing or two about Petroleum Geology. Thank you for this.

I think the correct term here is an analogous well/reservoir. A reservoir can be used as an analogy for another if it meets certain rules or tests. In my reserves days at Shell, had to be within same basin, then there were a number of other characteristics/tests that had to be met (sadly most of which I have forgotten, but recall that porosity/permeabilities/type reservoir needed to be similar). If it met the majority of the tests, then you could use the analogous reservoir to estimate a recovery factor usually. This was usually early on in the process, then as you gathered more dynamic data (psi/production) you'd move away from the analogy to methods more based on material balance & physics.

I know when I left Shell, they were looking hard for gas for Atlantic Train 1. At that time each of the trains had different ownership and gas dedications. I am not sure if this is still the case, I have seen some conflicting data on. Would think that for Shell to be interested, they'd want control of the gas, and all of Ortoire appears to be dedicated to NGC. Would also think Ortoire would need to get into the multi TCF range before they would give it a hard look. But I have been gone now 6 years, so my reasoning is pure speculation now.

The focus for Shell as of late has been strengthening the balance sheet. My understanding from what they have said was that they were having to borrow to sustain the 5% or so dividend. They cut back on the dividend last year as I recall, have raised back a bit here and there. Permian is a very capital intensive business, need to keep drilling to offset fairly steep declines of tight sands. Tight Oil/Gas is generally a better business for low cost driller/operators, and Shell is not that. Shell played in the Barnett, Haynesville, Eagle Ford, Permian, Pinedale, Duvernay/Canada, and Marcellus. Marcellus remains, with an Ethane Cracker supposed to come online 2022. Not sure status of Western Canada, was talk of trying to mature it into an LNG project, although that seemed like a long shot to me when I was there. In a lot of these plays, Shell was a late comer and missed out on sweet spots in the play with high recoveries and exited fairly early on. If I did the math right, looks like COP paid about $42,222 per acre, not sure what ratio of developed to undeveloped was, but looks on the surface like a good price was obtained. May be focusing offshore Brazil also, they got some sweet acreage from the BG deal. GOM has always been good money maker for them as well.