Member Info for Oleo

On page 21 you find the information that the Amungee NW 1H is completed with a 2 3/8" tubing. This is a small tubing. On the one hand such a small tubing can help you during production to prevent liquid loading. But on the other hand one problem is that you cannot use big diameter coiled tubing. And for drilling out bridge plugs in long horizontal sections the bigger the coil the better. So they have to use a small diameter coil and with such coil you get buckling and not enough weight on the bit/mill in long horizontal sections. That could be an explanation why after 200 m the operator was not able to drill and clean out the other 80 % of the not performing horizontal section .

I do not know the diameter of the tubing of Kyalla 117. But could be that they have installed a small diameter tubing there as well?

If yes, they drilled two times 1,000 m horizontal sections and after completion with small diameter tubing they reach the technical limits to drill out and to clean out the frac/ bridge plugs with small diameter coil thru tubing.

One solution could be to use a well tractor in combination or without the coil - but I would be surprised if they find a well tractor small enough for 2 3/8" tubing.
The other much more expensive solution: kill the well, call in a work over rig (but will need a BOP), pull the tubing, mill the plugs and restrictions with a drill string, pray that you have not damaged the fracs/ formation, do the recompletion and try to lift the well with a small diameter coiled tubing thru tubing again (or use a sliding sleeve ). And then we will see that all 11 frac stages kick in with gas and hydrocarbon condensate production, hopefully with not too much produced frac sand, otherwise we will need more CT jobs .

Had some time to read the Sep 2021 presentation more carefully. I really appreciate the quality of the slides and communicated informations.

On page 7 , borehole schematic: there you can read that all the plugs deeper than the casing diameter restriction are undrilled. Hmm, you do not need an expensive production logging to verify that there is no or just a small fraction of the production coming from the section with the not drilled plugs. This is a no brainer. What you need is an analysis of the restriction and then drill out the other plugs ASAP - and not waiting for another rain season.

Another perhaps critical point concerning the design of both (!) wells for the future, when the wells will be produced. You can see that at both (!) wells the heel of the horizontal section has a higher TVD than the toe. This is not a good idea at all because fluid slugs can accumulate at the heel , holding back and restricting potential gas production from the toe (after the operator has solved the two casing diameter restrictions)

Again: seeing this issues, it consolidates my image that the current operator is an amateur . And Fog, even as a 20% partner there should start to put pressure on the operator, should start to ask questions, should ask for meetings should talk, write a letter to the management of the operator etc. Because at the end of the day it is our money (even we are carried by the operator at the moment), fellow falcon sufferers.

As I currently understand from the published infos, I really see a know how and a lack of experience problem in the Beetaloo with the operator. POQ, please tackle this problem or proof that I am wrong.

We have created and ended up with technical problems at both (!) wells that make it difficult and delay the proof of commercial production rates in our Beetaloo asset. And without this proof we won't get the planned monetizing.

And I think we need to get a root cause analysis and we need to know if this bottelnecks (flow and diameter restrictions in the casing) in both wells in the horizontal sections are a coincidence OR if the operator made a mistake the first time (what can be forgiven) and if the operator made the same systematically mistake a second time at the second well (what cannot be forgiven).
From the September 2021 presentation
1)
Amungee NW 1H
Stages 1-7 low contribution likely due to restriction from the casing deformation and/ or the plugs having not milled out
2)
Kyalla 117
Production was not sustained and there was evidence of a potential downhole flow restriction

At least Fog/POQ gets one "thumb up" from me for shooting straight and for not hiding the technical problems. For us it is much better to have this information instead of guessing in the dark and watching insiders selling down without this information.

Schlemiel, who is "he" from "he says nervously" ?

My own very rough , conservative napkin calculation is a 10 % recovery factor - but nobody knows this number today (sometimes even after 40 years of production you cannot be sure about the exact number of the recovery factor - moreover the RF is influenced by the oil price which makes it more difficult to predict).
The higher the production rate, the less the number of necessary production wells, stimulations = less costs. The higher the production rate, the better the reservoir and a higher recovery factor can be expected (as long as no natural fractures filled with reservoir water or the like show a premature high water cut. )

H2
Hmm, I am afraid Fog/Org still do not have enough measurements, logs, data to get the exact picture or interpretation of the downhole restriction situation. Otherwise they would say this is the concept to remove the restriction or they would say the big investment for removing the restriction does not justify another workover and we have to live with this restriction - right?

"""How does Origin go about doing a 60 day production test when the deformation is still there restricting the flow to all but the last 200 meters...""" The longer you produce the better. First you can hope that you perhaps increase the delta p for the other 800 m with the time and hopefully the other 800 m start to kick in slowly as well. The longer you produce you will get more information/ data from the deeper part of the reservoir. So when the first 200 m are dominating you could hope to get data from the first 200 m but from the deeper part of the reservoir, which is good to get more knowledge about the reservoir.

H2, what was the exact question?

I do not think that Fog has got a marketing/public relations problem for selling the company or shares of the company although I am sure Mr exCenkos could offer some good advise and tricks to POQ.

One problem of Fog & Org is know how and an operational problem as the flow restrictions in the horizontal section of the wells and we need an objective evidence for the commercial production rate to get the $ from the Japanese for example. In the neighbouring concession Tamboran is tackling this expensive learning curve:

""" To assist with this goal, Tamboran has leveraged the Beetaloo’s similarity to the Marcellus Shale by hiring a US team with experience in the Marcellus and other shales.

“The advantage we will have is that the team that is going to be designing, drilling, developing the assets that we own are the guys that have drilled actual wells into the Marcellus in the past,” Riddle explained.

“They understand the Marcellus shale learning curve, they understand what it takes to get the well cost down.”

“In the Marcellus, the early wells cost $15-20 million to drill and frac and US operators got them down to $5m or less. We see a very similar learning curve happening in the Beetaloo in the next few years.”

He added that leveraging on the team’s expertise will be key to getting the learning curve down quickly. """

The longer the production is tested, the more information from the reservoir you get the better the well test interpretation.

@ newto
Especial at wells with long horizontal sections it is a simplification to say if you got 1 mill cft from the first 200 m than you get 5 mill cft from 1,000 m.
a) physics works against this simplification: the pressure draw down at the heel of a horizontal waell is always bigger than at the toe. That means the better draw down at the first 200 m creates better conditions for a good flow rate than for the other 800 meters.
b) in most cases geology works against this simplification: very very seldom you drill a homogeneous reservoir. Geology always shows heterogenities. That means important reservoir parameters like porosity, permeability, saturation, wettability etc, are influencing the flow rate in different sections

My surprise was big when the share price went up 100% and another 40% within 2 days, but the current declining share price is not such a big surprise. We have seen this pattern not the first time.
The raising share price caused too much euphoria, because the 5 million cft/d /1.000 m are a calculated number, not a real produced nor a measured number. We cannot be 100% sure if this number is 100% correct or not. This calculation could be a small step into the right direction and it could become the game changer number in the future perhaps - but as of the day of publication it is not the game changer news as some have published or discussed already in my opinion, because the 5 mill ctf per day per 1.000 m horizontal section have a risk as a number and are not the reality. Perhaps this is the reason that it took so long till Org echoed the Fog publication as well?

But I am surprised that the Swiss Nicolas Mathys is selling after so many years as a long time holder from 4,5% to 40.000.000 shares. What are the reasons?

No surprise when a part of the 4,9% or 48.101.000 common Fog shares from the left overs from the Sweetpea / Petrohunter bankrupt are sold.

As long as we do not see the clear proof (and not just a dodgy perhaps calculation) that the Beetaloo, respectively Fog's asset can deliver commercial production rates as a hard fact, we will see this rollercoaster share price as we see now. And I am afraid without this hard fact for the proof according to commercial production, no mayor big oil company, will offer many billions of $ for our Fog shares.

PS: I liked this article from South Africa, posted here, but than I realized that it is an old one. This article could describe a possible playbook and I see the potential in South Africa that has to be offered to the market and to South Africa much more proactive by Falcon, otherwise we could oversleep the changing situation in South Africa (and I do not want to watch how POQ gets paid this salary for another 15, 20 years, trying to make a deal in South Africa). Hello FOG, it should be possible to work on South Africa and Australia parallel.

With or without South Africa, which could be another monster gas reservoir?
At least 1 billion for the pessimistic case, 3, 5, 7 ... billions for the blue sky case.

All this euphoria, this rising share price on Friday have put a smile on my face.
BUT IMHO, this RNS should be taken with some grains of salt:

"3 September 2021 - Falcon Oil & Gas Ltd. (TSXV: FO, AIM: FOG) is pleased to provide results of the production log test at the Amungee NW-1H well ("Amungee"). The results suggest a normalised gas flow rate equivalent of between 5.2-5.8 MMscf/d per 1,000m of horizontal section."

What does it mean? It means that Org has run a production log into the flowing and producing well. So far so good and a standard measurement to get a better understanding of the well behavior and to identify the sections of the well from where you get the gas, perhaps to get the section from where you get liquid hydro carbons, for sure to see where you have water entry points and which perforations, frac stages do not deliver any hydrocarbon production (although it took a too long waiting time till they ran the successful PLT finaly)

We can learn from the RNS, from POQ and from Cenkos that about 80 % of the at surface seen production comes from the 200 m horizontal section beyond the damaged or restricted casing. Thumb up for this point because it is verified by the production log i.e. you can bet on this measurements and log interpretations .

But than it becomes a little bit dodgy for me and I wish POQ would have added some more information to his RNS.
The log ran 200 m and the well has a horizontal section of 1.000 m. So Fog just multiplied the production rate with the factor of five and created a headline about a world class production rate of 5 million cubic feet per day per 1.000 m. This calculation is too simple for me.

For me it would be much more trustworthy if they would have published this calculation PLUS the basis, the assumptions for this calculation as well.
Perhaps like: based on the open hole logs, based on the cores, plug measurements and analysis we assume that the drilled 1.000 m horizontal section show more or less the same reservoir parameters (like porosity, permeability, saturation (yes, for me this important infos and data about the saturation are a missing link for the whole picture), mineralogy and so further), based on the assumption that the frac stages deeper and behind the damaged, restricted casing show the same production performance as the first 200 m of the well ... we can assume the world class production rate of 5 MM cft / d / 1,000 m.

Newto, thank you for the answer and the links. I think it's worth to re read this links.

BUT on the other hand, look at Total. Recently discovered and first gas expected in 2025
https://www.upstreamonline.com/field-development/luiperd-early-production-system-in-sight-for-totalenergies-offshore-south-africa/2-1-1052001

Newto
I think it is the right way, that POQ has invested some effort into South Africa. But IMHO it is a big mistake to let the Karoo field in South Africa rest, because things are changing in South Africa compared to 2, 5 years ago
- Total has discovered big offshore gas and condensate fields in South Africa recently
- The South African government plans to burn less coal and less diesel for power generation

FOG has to do some lobby work in Africa now and again, because for South Africa it would be a much better solution to export the offshore gas, condensate and burn the shale gas for power generation than to burn the offshore gas for power generation.

Drilling another well is good for the learning curve and a successful diagnostic fracture injection test will be another small step into the right direction.

But what we really need is a production test demonstrating commercial production rates = game changer.

Till today we got 2 horizontal, hydraulically fractured wells and both wells show a diameter restriction in the horizontal section = excuse that we do not have a game changer today.

Where is Fog in SA? Is the Fog asset part of the new petroleum bill in SA?

... discussing gas marketing with the government, which owns both the Eskom diesel power plant and the PetroSA gas-to-liquids (GTL) plant in Mossel Bay. The diesel power plant is able to burn natural gas and would like to switch fuels as soon as possible. Also, the GTL plant has been stopped with no feedstock since December 2020 because the Block 9 gas production has been depleted.

And POQ oversleeps the chances and opportunities for gas in South Africa.

Investment update
Bloomberg article from yesterday: Coal-Reliant South Africa Is Turning to Gas Power – the main points:
South Africa is the world´s 12th biggest source of greenhouse gasses
80% of its electricity is produced from coal
The government aims to cut emissions to net zero by 2050.
SA plans to use natural gas to produce at least 25% of almost 12,000MW of additional power by 2030
SA already imports gas from Mozambique, but further gas development there is limited by an Islamist insurgency.
The primary source of gas for the SA´s is the 11B/12B that AEC owns 10%.
https://www.bloomberg.com/news/articles/2021-08-03/coal-reliant-south-africa-invests-in-gas-power-to-go-greener

Thanks for the satellite images. Some water was brought to the well site.

With totay's date I think it's not correct to say the water saturation is no longer an issue.
Still I have not seen any hint that the water saturation is low enough for a good prognosis for the hydrocarbon production. Additional we have one more problem, the new restriction or hold up in the well, that has to be solved first and before the next steps can be done.

Lets hope the planned new vertical well with diagnostic fracture injection test is a much needed success, although a horizontal well with many frac stages and a sustaining commercial production rate would be the best proof for commerciality for our Fog Beetaloo asset.

Falcon Oil & Gas pauses shale well after production not sustained
Tue, 20th Jul 2021 14:11
(Alliance News) - Falcon Oil & Gas Ltd on Tuesday said it has paused operations at the Kyalla 117 well as production could not be sustained, with evidence of a potential downhole flow restriction.

Shares were down 15% to 5.15 pence in London on Tuesday afternoon. They have dropped 43% so far in 2021.

The company had started up the shale well in Northern Territory, Australia - operated as a joint venture with Origin Energy Ltd - last month. But it was only able to flow without assistance intermittently.

"Operations will now be temporarily paused while the cause of the restriction is investigated, the results of which will inform the development of a new go-forward plan for Kyalla 117," Falcon said.

"In the meantime, the JV’s focus will continue on other elements of the work programme. The JV remains on track to drill the Velkerri 76 well and commence a further extended production test at Amungee NW 1H in the coming weeks."

By Ivan Edwards; ivanedwards@alliancenews.com

Copyright 2021 Alliance News Limited. All Rights Reserved.

Interesting info Darnit.
I have been involved in several 4.O and AI projects in the oil patch. Met many bright people from big companies, research institutes, small start ups and University during this time. My conclusion: seldom, very seldom you earn money, produce more oil, gas by applying this technology today. Perhaps one day in future it will work, who knows. What I have seen is that people did not get the (often sophisticated) basics right. If you get the basics right your pump will run without problems and you won't need AI to deliver an average performance. Management likes and supports visionary AI & 4.0 . So they get this pilots..