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I am disappointed that we hear nothing from South Africa from POQ and Fog. The big boys are active in this area (see page 5) and there is a market (see page 13)
https://www.invictusenergy.com/wp-content/uploads/2021/09/61051419.pdf
And Posco plans to buy Senex, another small oil company in Australia
https://www.reuters.com/business/energy/south-koreas-posco-international-talks-buy-australias-senex-energy-2021-10-17/
A production rate of 0.364 mmcft/d is not enough. This low rate reminds me of the shale gas gold rush in Poland, more than 10 years ago. More than 50 concessions were bought by small, midsize and even big oil companies. None of the drilled, fractured wells was a gusher and shale gas is dead in Poland today. I hope the Beetaloo is no deja vu. We need a real commercial production test rate ASAP in down under.
The good part of the Carpentaria news, they want to drill 7 (!) wells, that means the high number of trials can increase the probability to hit a good production rate
"On 14 September, coil tubing operations recommenced at Kyalla 117. No apparent restriction or blockage was identified in the production casing."
- What happened to the restriction, blockage, that was offered as explanation for the poor performance of the well at the beginning?
- Did the operator run a caliber or better a caliber log with the CT to see if the casing is deformed or not? At least this section of the casing can be passed with a CT, that's the good news for today.
- Did the operator try to find out if the not anymore apparent restriction was just some frac sand or halite?
- Or was the interpretation of the restriction just wrong and the hold up from the effect of a dog leg was wrongly interpreted as diameter restriction of the casing?
The bad news, the issue with the water saturation (Sw) becomes more severe (my interpretation with limited data and info). Obviously the well does not produce enough gas and produces too much (reservoir???)-water , ending with a liquid loading problem, which kills the well finally. This finding is now proved two, three times at this well and today the excuse with the restriction as bottleneck does not work anymore. I cannot be 100% sure, but we get more hints that the Sw is too high in this reservoir for a commercial production at this location.
If this Sw interpretation is wrong, the operator should have kept the CT unit on location and should have lifted the well a second, third, seventh time to help the gas to remove the water block(?) from the spent frac fluid. Another point: I think we were told that the spent frac fluid did not damage the formation. Where are the proofs for this information of no causes skin in the well or was that just the 1:1 answer on the phone from the sales engineer of the service company that pumped the frac ?
Another hint that we got amateurs here "On 14 September, coil tubing operations...": you got a coil but it should be called coiled tubing and not coil tubing
Comparing the Beetaloo with the Jafurah.
Starting in 2024, SA estimates that $ 110 billion have to be invested for wells, frac stimulation, pipelines and facilities to produce the unconventional Jafurah in the neighborhood of the biggest oilfield on earth (Jafurah could use some infrastructure of Ghawar (?) and no Green party Lock the Gate)
The field's production is expected to reach 2.2 billion cubic feet per day by 2036 along with 425 million cubic feet per day of ethane and 550,000 barrels per day of natural gas liquids and condensates.
https://www.energyintel.com/0000017c-0d83-de48-a9fd-1fcf4b1c0000
Hmm I am complaining that others do not have professional plans but on the other hand I send a letter with grammar problems - you understand what I mean.
Do you have POQ email address?
I am desperate because I see the technical problems derived from the power point presentations but do not see the mitigations
I am desperate enough to do that. But I would like to get some help with the wording from somebody with the mother tongue English because it should become a high quality letter or mail.
If I could get an email address, I would send you an appointment and an MS teams link?
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.
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.
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