Member Info for Oleo

By the way:
On the katherinetimes photo the white crane is holding Halliburton red CT equipment (BOP, lubricator, stuffing box, tractor, goose neck, coil )

https://www.katherinetimes.com.au/story/6933446/fracking-to-start-in-the-beetaloo/?src=rss
Here you can see the U better. In front of the U is a flare stack and inside of the U another flare?
We have to concentrate on this U area.

Thank you deprussky.

On the photo you see the crane. At the crane hook, there is the wellhead. The Halliburton red equipment is the frac equipment. On the other side of the wellhead you see the cutting pit. On the left side they placed some white containers like an "U". And inside of this U, there is the flare (not burning but installed)

https://m.facebook.com/TheOriginBeetalooExplorationProject/photos/pcb.213651956765232/213651583431936/?type=3&source=49&__tn__=EH-R

NoS, this explanation I understand!

Animal: liquified nitrogen is transported with trucks on roads world wide and I assume in Australia too. It is a standard procedure for CT companies. They buy the LN2 or they own units to get the liquified N2 from the air. The biggest risk: you can freeze your fingers when you do not wear gloves as personal protective equipment.

Deprussky, we need your satellite link again, if possible? I think in the Org presentation was a photo, where the exact position of the flare was shown. So , perhaps we have a chance to identify a big flare, burning many days, some weeks, even with the low resolution satellite images. I would give the infrared mode a try.

I am glad. Today's operational update is technical risks- and shareholdermoneywise much better than sitting around and twiddling dumbs.

But I would be surprised when we see some remarkable hydrocarbon condensate volumes this time. However, I think if there is some gas and when they can lift a higher volume/rate of reservoir water compared to the volume/rate of the reservoir water inflow (from the heel section?) so that we can get a delta p where the potential gas is still trapped by the spent frac fluid somewhere in the toe section, then we will have a chance to see a production test with a gas rate and a burning flare. Fingers crossed for this probably last chance.

If we see water only again? Water shut off is always difficult in such a horizontal well (I am not aware that they installed swell packersor or was the whole annulus of the horizontal section cemented?) Then this well could be used as water disposal well in the future perhaps but not as production well.

Do you mean Gabor Bada? I am not sure if he is the right person. He is a geologist and from his linkedin profile you can see he is an expert for G&G , although Fogs homepage tells us he is responsible for technical operations. Here you need now expertise about reservoir engineering, well testing and intervention, production, petroleum engineering , knowledge that D.H. Gilbert should have.

I was not happy to wait many years for the Beetaloo but I accepted it because of external factors, difficult to influence. But now it is a no go to delay operations in the Beetaloo with ridiculous arguments, jeopardizing the success and wasting time and money by stretching the timeline "premeditative" .

"...so why spend the money, if you can just wait and see that gas/condensate will push the water out"

There is a very, very small chance that this concept works because the well killed itself with heavier reservoir water. The well is dead and in the best case some gas will bubble through.

Yes bigones, a pretty ridiculous situation from my point of view.

Some oil companies got departments called "joint venture influencing". The guys in such departments oversee the non operated assets where in most cases the other partner and operator is the dominant share holder. So, how do this guys earn their salaries: this guys check the costs, the production numbers, the revenues, the work programs ... the operator is presenting them. If this guys discover a mistake or think they know it better than the operator, they ask to clarify or suggest technical better options and solutions. If you have a rational thinking and acting operator, who takes advantage from this win win situation, you end up with an optimised, better solution.

The announcement from Fog suggests that Fog swallowed ORGs suggestions for the next steps.
Id est accepting some risks that the well could be damaged after 5 months,
Id est Fog does not care to lose 5 months and more for the 60 days production test, as somebody explained here already. And Fog does not care that we shareholder lose another half year or perhaps even a year when you take the duration of the production test plus interpretation of the generated data and surprisingly the rain season 2021 into account.

I expect from Fog in Ireland that they contact Org and start a discussion about this topic. POQ is known for his negotiation skills? Here is a chance to prove it.

Swabbing or lifting a well is no big deal at all. It is a standard job routine for small money worldwide, and should including the Beetaloo.

The real question is: why do we see this hesistant delay

We got 2 uncertainties here now (as I interpret it):
1) can we be sure that the operator applies the best workflows, work programs to get the optimum
2) is the water saturation of the reservoir too high or not

Alternately, Origin can shut in this $60 million dollar well and hope that nothing goes wrong over the next five months, AFTER they confirmed they recovered the recoverable pumped and spent frac fluid.

With 500 bbl/d or less I think no. I think it could be that only the spent frac fluid from the stage with the reservoirwater source has flowed back from the heel part of the horizontal well section. Could be that the other stages are still full of spent slowly aging frac fluid, creating a waterblock and damage for some potential gas deeper in the reservoir.

Or the other scenario: they have sampled the reservoir water with too small gas bubbles and no hydrocarbon condensate. And Org assesses the situation so pessimistic that they want to give up but want to tell it us in about 5 months because they do not want to tell us this now.

VilllaM
Yes
But many if s in this case. For example they close in the well. The frac, the reservoir does not get damaged during the shut in. The small gas bubbles come to the well head and create a gas cap and perhaps even push back the salty reservoir water back into the frac, reservoir.
But such a well will not make us happy because gas production wells with high water cut are not good performing production wells.

Green, I do not hope so. And instead of using coiled tubing and nitrogen it could be done with smaller budget and no nitrogen either. With swap cups or another alternative could be a cap string. And this alternative technique is with a slick line unit only possible too.
Yes CT is common as Fog and Org said, but if you know the common only you are limited. I've got the notion Org knows the common only and plans without contingency.

“Work both on and off site will now focus on continuing to flow back the well while planning this additional work, likely to occur in early 2021 following the wet season.The option to temporarily shut in the well is being considered as part of this activity,” Ms Boyes said.

Does not sound like a goahead from Ms Boyes.

When do we get answers without "if". Waiting for decisions, and hopefully for the right one.

"...if successful, will allow extended production testing to commence. This..."
"....If a decision is made to temporarily shut-in the Well, operations will resume in early 2021...."

Commonly oil companies are aware of this bird, reptilian etc. problem and take measures. Even oil companies are not anymore in the 1970ies.

One more thought:
In the Org presentation you see the evaporation pit on the photo for the produced reservoir water. A technology Org is applying for the coal bed methane wells. If it is raining evaporation pits are the wrong concept. But again, another solution for this problem could be done.

Attributing; For lonely solyomtwo at agoracom.com:

Without having been at the well site I could write the book for the situation and the phonecall there:

Companyman: : Hello Boss
Manager: Hello Companyman. Do we have a burning flare and which rate?
C: Ahm, only some small gas bubbles and we have difficulties to light up the flare.
M: Hmm
C: And the well is killing it self .
M: Why?
C: The salt content went up and increased the hydrostatic pressure.
M: What can we do?
C: We would need a CT unit but difficult to bring in during wet season.
M: Hmm (after some strategic considerations for himself) ok we delay,

If they really think they could get the well lifted with CT and start a sustaining test production in some months, they think that the condensate, gas is there.

But if the gas and condensate is there, it could be managed if you really want it, now too.