The latest Investing Matters Podcast episode featuring Jeremy Skillington, CEO of Poolbeg Pharma has just been released. Listen here.
https://www.carnarvon.com.au/report-from-the-rig-with-george-mills/
Posted yesterday on the Carnarvon website. It's of general interest and also has a couple of interesting points At the time of writing this they were running 9 5/8" casing. So casing run probably no later than Saturday. I would expect that they are now drilling ahead in 8 1/2" hole.
Also they are running MWD/LWD tools on the drillstring near the drillbit. The MWD (Measurement While Drilling) tools take mechanical measurements while drilling: such as downhole torque, rate of penetration, downhole weight-on-bit and downhole pump pressure and mud weight). The LWD tools (Logging While Drilling) contain at least a simple Gamma Ray and Resistivity tool (could be porosity tools as well but not necessarily). The MWD tools help to drill the hole efficiently while the LWD tools will be able to tell when they enter the reservoir and whether there is any oil there during drilling. These tools should also be able to detect the oil/water contact. Data from these tools can be transmitted to the surface while drilling and they almost certainly have an online monitoriing system where the Carnarvon staff in the Perth office can watch the data come in live,. These downhole tools do not replace wireline logging which will be run after reaching TD and are more accurate.
Thought this might be of interest.
I don't think this changes the expected progress and suggests that the reservoir is still a few days away.
Basically the CEO has over-promised and under-delivered. He claimed that the oil discovery that was made in Royston-1 was the best he'd seen in all his time in the oil Industry. The tests then produced low oil rates with a lot of water. Personally I think he is not being objective and is infatuated with his "oil discovery". They have discovered gas which is close to getting developed and hopefully coming to production soon which will be transformational for their cashflow, but instead of waiting for this he is planning for more exploration and appraisal wells. He's fallen in love with the exploration potential instead of looking after his core production business and balancing the books. There is a cash shortfall so they have just extended their loan facility and I can see an equity raise coming down the track unless they get their gas production on quick. Its a very Canadian way of managing the oil business by chasing rainbows.
I'd saw the same article and it piqued my interest as well. Unfortunately, a lot of presentation material which Pensana say is on the website simply isn't there. I would look at the risk register in the annual report starting on page 31. Sovereign risk in Angola is the one that resonates with me. China dominates the rare earth market and Chinese companies have built port and rail infrastructure using state backed debt under the "one belt-one road' initiative. This gives China plenty of access to the Angolan government which has a poor reputation for corruption. I believe that if China saw the Longonjo and Coola projects as a threat to their rare earth markets I would be concerned that they would try to "influence" the government and try to delay the implementation of the projects. I'll continue to have a look at the presentation and broker material but at least half of the project looks a bit risky to me.
The RNS's should be restricted to what is "Material". I would say that there is likely to be an RNS once the well has finished wireline logging and this may include some statement such as "met expectations, exceeded expectations, below expectations etc but unlikely to give specific numbers. A RNS would normally be released when a new Independent Reserve Estimate has been completed, financing completed, when FID has been declared, and / or when government approvals have been granted. A field development plan is likely to be announced with one of the other events. These are the main events, they could also make announcements on securing a MUPU or FPSO. Of course the companies are listed on two different exchanges and so could claim to be under slightly different rules but in general there are disclosure clauses in the joint venture agreements which require approval by the operator.
I'll deal with the well depth first. The well will have been designed to penetrate to a point below the previous oil / water contact. Although the reservoir has been drained of oil up until the abandonment oil/water contact there is merit is looking at the residual oil saturations so that they can use it estimate what % oil recovery they can get from the undrained attic reservoir. Without going into technical detail not all oil in the pore space of a reservoir can be recovered as some "sticks" to the rock and is left behind as residual oil. In order to log the section the well needs to be drilled a little deeper that the desired zone to be evaluated so that all the tools can log the section (the wireline tools are all stacked in a string and could be up to 30 meters long). Of course this still doesn't get to 3500 meters The problem is that all the reservoir tops and fluid contacts are based on the seismic which are measured from the seabed. The well is drilled from a datum on the rig (the rotary table on the rig floor). The proposed well depth of 3,500 meters is measured depth, it says so on the RNS's. So the seismic based depths need to be adjusted. I would add 30 meters for the water depth and 30 meters for the "air gap" which is measured from the sea surface to the rotary table. After making these adjustments the original OWC is at approx 3376 meters Measured Depth. Add a further 30 meters in order to get the wireline tools in and you get 3,406 meters. The extra 100 meters could to ensure that they get into the aquifer and possibly some "rat hole" as insurance in case some of the hole collapses at the bottom. So no ,the additional depth is not just-in-case the OWC is deeper than the original discovered OWC, it simply can't be.
As for the completion. They are planning to run a 7" casing which in the oil industry is referred to as a liner. This is not run to surface (to save steel and cost) and is "hung" from inside the 9 5/8" casing. This would be run and cemented in place and left unperforated to ensure pressure integrity prior to production. The 5 1/2" tubing will later be run after the wells is perforated across the production zones. The tubing ii sized in order to get the high volumes of fluids through due to the use of electrical submersible pumps (ESP's). The language that is variously used about deciding whether to run the completion or not partly reflects the restrictions on disclosure of information (forward looking statements) and partly reflects the commercial chance of success being ascribed to the well (i.e. its not 100%). Its simply a decision that formally needs to be made by the joint venture after drilling the reservoir. In reality they have all the 7" liner and equipment on board and so they plan for success rather than having to dispatch a boat out to Darwin to pick everything up and rack up very expensive spread rates while waiting for it to arrive to the rig and be offloaded.
Sorry this current casing point is the 9 5/8" casing (not the 13 3/8" casing) and they will be drilling ahead in 8 1/2" hole.
Ok, here's my quick take. The Carnarvon RNS didn't really give much away and was ambiguous "with the geological
markers in the 12 ¼” hole section having been intersected within the pre-drill range". The one from Advance wa a little more informative. "we remain on prognosis is an encouraging indication that the geophysical interpretation is as we predicted". So the well is on track and on prognosis. The setting of the 13 3/8" casing is however around 93 meters higher than planned. The well will have planned to get the casing seat into shale and the obvious target is the top of Echuca marine shales, so they have probably hit this lithological change a little higher that prognosed. I wouldn't read too much into this just yet other than its encouraging that it's been encountered higher (shallower depth) than originally prognosed which supports the geological model of a high at the reservoir level.
So its game on now. They were preparing to run casing on Friday morning (Aussie time) and this is a much simpler operations than the 13 3/8" so anywhere from 36 t0 48 hours until they drill out the cement and drill new formation. They are in a section of the hole which drills quite fast and they have 500 meters +/- to go. I would estimate around mid-week to the top of the Elang (the reservoir).
I've seen some other comments in other threads which refers to Leslie saying that they will know where they are immediately after drilling out of the casing. This was in a interview with IG in October?. I've watched and listened to it again and I think he is giving the wrong impression. They cannot know where the Attic is until they penetrate the top of the reservoir which is still a significant distance away. Rest assured there will be an announcement when the top of the reservoir is hit with oil in it, it just won't be for a few days yet. So in a nutshell its all there to play for, its encouraging that they are making good progress and "on prognosis" but we still need to wait for the RNS which provides a depth of the top of the reservoir and the magic words oil. Given the material nature of the information I expect an RNS later this week, maybe Wed night UK time / Thursday morning Aussie time. And a follow up early the following week when the wireline data has been completed and assessed. They will need to make a decision on completion of the well and so will probably include that with the 2nd RNS.
Just a few more days to go now.
I've reread the section on the seismic reprocessing and I'm not surprised that you are struggling to read or understand it, its full of advanced geophysics. So I'll keep it simple. The reprocessing of the seismic has re-positioned the top of the reservoir. It has also done the same to the seismic imagery immediately above the reservoir. Some of these events are distinct and mapable markers on the seismic and will have target depths. If they are distinct lithology breaks then they can be picked easily and should be able to indicate if the well is on prognosis or not. Now the not so good news. I think all the key markers that they will look for are from the top of the Echuca Shoals formation which will be encountered just above the next casing point. I'm not sure that Carnarvon will make any mention of this in any press release though. From Leslie Peterkins interview today it also looks like they may be a few days behind schedule which would put the penetration of the reservoir conveniently on a Saturday.
A number of people have asked when this current hole section will be finished. I have looked at some offset well data and the current section of hole is normally pressured and drills at pretty high rates. On Thursday (AUS Time) the well was at the 13 3/8" casing point. Running casing and cementing in place, installing the wellhead and testing the BOP's, drilling out the cement and testing the formation should take around 2 to 2-1/2" days. Maybe a little longer as they are usning a mud line suspension system to allow for suspension of the well. So they should be drilling ahead now and the section could take anywhere between 5 and 7 days to drill (I don't know what kind of bit they are using and if they are using oil based mud). Baring any problems they should be at 2800 m MDtvd by end of this coming week.
@dai2belts Coring requires pulling the entire drillistring out, changing the bottom hole assembly and adding a core barrel, running in the hole with core barrel and acquiring the core. Pulling out of the hole with the core barrel and then changing the BHA again and running back to recommence drilling. This is very expensive , adding at least two days to the drilling program. For sidewall cores they can run them on wireline which is quick and low cost by comparison. Not as good as the full core but if they use rotary sidewall coring they will likely get useable rock data.
It's even more expensive to do a test. The rig will not have test booms, a testing manifold, seperators or any of the other test equipment required and so this will all have to mobilised and rigged up. You don't test through drillpipe and so testing tubular have to be bought out by supply vessel and loaded onto the rig in single joints and then made up (connected) one-by-one. At the bottom of the test string are a lot of testing gauges and values etc that have to be bought (or rented) and after setting the testing string in place, the drilling fluid in the 7" liner will have be replaced with a testing bring and then after pressure testing the liner integrity wireline and testing guns will be run to perforate the liner. Then you have to run the test which will consist of various flow periods and shut-in periods etc. Upon completion, the well needs to be plugged and made safe for suspension. This is a summary of operations it's a lot more detailed than that. We are talking of millions of dollars of extra expenditure, the more you test the higher the cost. It's more cost-effective to run a MDT tool on wireline to pressure test and take samples in the open hole before the production liner is run.
Casing in Buffalo-10
The surface 13 3/8" casing is a fundamental part of the well safety and has pressure tolerances to protect from bursting from potential higher pressures drilled in the next open-hole section. The well program has this section to be drilled quite deep (obviously, there is no shallow gas) I suspect its due to a thick carbonate section and the desire to get a casing seat set in shale for pressure integrity Casing is nominally provided in 40 feet sections but has a variance of +/- 2 feet and so, like the drillpipe, each joint is measured individually. Roughly there will be around 69 joints of casing. At the bottom of the casing string there are various cementing and running devices - the float collar, is further up and at the bottom a casing shoe (or float shoe) allows the casing to be circulated but stops debris getting in the casing. The float collar also stops the cement from, flowing back into the casing after it has been pumped. Getting this casing sting in place and properly cemented is a critical well control feature particularly when the next open hole section is 2,000 meters long. Once all the lengths are worked out the hole will be drilled to the appropriate depth leaving a small hole space at the bottom called a rat hole. The original hole depth of 800 meters was probably drilled a few meters deeper to allow for the actual casing string length and spaced out to land into the mud line suspension system- which I assume they are using and will allow for the well to be suspended at seabed for later tie-back to the WHP. Once landed additional casing is then run from the seabed to the drillfloor where the wellhead and BOP's are attached to facilitate support of the casing and to allow well control. Once all this is set up, the casing will be cemented in place and after once the cement is sert a drillsting will be run and the cement will be drilled out of the casing. A then a small amount of new formation drilled and a pressure test done to test the cement integrity around the casing and test that the formation integrity is sufficient to withstand the expected formation pressures in the 12 1/4" hole section. After all this is done drilling of the 12 1/2" hole section will commence.
So why such a detailed answer? Well, there is a lot of impatience on this board about drilling progress. In think its best to keep in focus that the entire well has to be drilled safely, in accordance with the regulators requirements, and suspended as a primary production well. To do this takes time and definitely you want the to be drilling safely and keeping the well in good condition. Look on the bright side only about another 15 or 20 days and we should have a full announcement.
@dai2belts that's a curious question to ask, but here goes. The drillstring is made up of three main parts which are determined by the useage, mud weight (buoyancy), abrasiveness of the formation, strength of the formation and designed to withstand the pressures and chemistry of the fluids running through it (both inside and out). The main component is drillpipe (DP), below that is Heavy Walled Drill Pipe (HWDP) to provide extra weight and often is more flexible making it useful in directional wells and then the Bottom Hole Assembly (BHA) which provides weight,for the drillbit, stability by the insertion of stabalizers , may contain jars (for getting unstuck), downhole tools like MWD (Measurement While Drilling) and LWD (Logging While Drilling) and of course a drillbit. The problem is that not all the pipe is of equal length (drillpipe is supplied with a variance from the mill and they can stretch in use), variance is from 27 feet to 32 feet but on average is 30 feet. The collars and BHA components are of various lengths and are all measured individually (normally by metal tape and by hand). Because of this variance all the drilling components lengths have to be measured and tallied. In drilling the drill sting is combined into joints of 3 called a stand and these can be measured once the drilling string is made up to save time. Yes its a manual business, yes there is engineering science behind it (there are different metal chemistries, different joints, different wall thickness, Inside diameters and outside diameters. Drillsting software programs are used in the design and adjusted to allow for hole conditions and whether the hole to be drilled is straight or deviated. A number of companies might be involved in the provision of the components, standdard drill string is usually provided by the drilling contractor, specialist parts (stabilisers, drilling jars, MWD or LWD equipment, Drillbit) by other companies. At the outset of the well all the components are loaded individually on a jack-up to reduce deck weight while towing (having previously being offloaded at the completion of a previous well if the rig was to moved any significant difference). This (and the loading/unloading of materials) is a major contributor in why completion and abandonment and well start up takes so long.
So for the answer to the drillpipe questions, nominal length per joint is 30' , because of the varying components of the BHA somewhere between 70 and 80 pieces of drillsting is my guess.
I'll answer the casing question in a separate post.
I'll make a few responses in this one post:
The arrangement between Advance and Carnarvon is a little unusual in that Advance are responsible for raising the funding while Carnarvon operate. However, their agreement is such that both have to agree critical decisions. With respect to MOPU vs FPSO, MOPU's have been very successful in SE Asia but have not been used in Australia. They are capable of operating on the field sizes and production rates contemplated for the Buffalo field. Besides being less capital intensive than a typical FPSO they can also support minimal well head platforms and hydraulic work over units. This considerably reduces the work over costs as a Jack-up rig will not be required. These costs could be significant because of the plan to use downhole pumps (ESP's) and the possibility of well recompletions due to water encroachment. At the end of the day its down to operating philosophy and in Australia they are more comfortable and familiar with FPSO's. In the RISC report they use the Capex and Opex costs for a MOPU and FSO spread and Leslie says that they have a couple of hundred page field development plan ready to submit. I wonder whether that includes a MOPU or FPSO? They have completely different operating philosophies which have to presented for approval by Timor Gap. If may have to be rewritten which would take time. Also Advance are raising capital so they also have a say. As long as everyone is aligned it will be OK, which is why its very important for Advance not only to find the right project but also the right operator.
I agree that heads of terms could already have been exchanged and for completion they will ultimately require satisfaction of certain conditions such as receipt of an Independent reserve report, receipt of government approvals, FID and potentially an offtake agreement. Although, if its a Bank led RBL, they would likely work with an oil trader anyway.
With respect to well progress, they may be at the 13 3/*" surface casing depth at 800 meters. But there is a extra work to do at this point with installing the wellhead and installation testing and functioning of the BOP's. We are just going to have to be patient, there are still a few weeks more of what should be fairly uneventful drilling.
Part 2 of the answers to Noeasy's questions:
Q3 Feeling slightly uncomfortable with the extremely favourable risk assessment made by RISC.
It's purely because I have not seen the raw seismic, well and production history data for the field to make a full qualified judgement. I have confidence in the auditor and the staff in Advance and Carnarvon which helps considerably.
Q4 Lastly being off by a leg on the seismic or the velocity model being slightly wrong could lead to what degree of oil in-place being sliced/added.
I can't be specific on numbers (ie. STOIP) but would be less concerned if the well came in a few meters low to prognosis but a more concerned if it came in 10 meters low to prognosis. There are other factors which could compensate for this such as improved reservoir net/gross and the Oil / Water contact being lower than expected (this is possible if the field contact has equalised after 20 years of being shut-in).
I ran out of characters in the previous post so let me add this. The MDT (which is designed to take downhole pressures and recover reservoir fluid samples) can take multiple pressures at different depths which can be used to calculate the oil gradient and the aquifer gradient this providing accuracy on the Oil / Water contact. It can also give some idea of reservoir permeability to flow, but establishing a definitive flow rate is outside the tools capabilities.
Hope this helps GL
@Noeasy, I have no problem answering your questions, which I will take in order you asked them.
Q1. Finance being tied to an updated CPR.
To be "bankable" the project needs an independent resource assessment which reclassifies the contingent Resources to Reserves as 1P (Proven Reserves 2P (Probably Reserves) and 3P (Possible Reserves). At the moment the resources are Contingent Low ( C1), Most Likely (C2 and High (C3). The well penetration will allow the Buffalo-10 well data to be integrated into the seismic (particularly the reservoir top) and confirm the oil water contact. The well logs will define porosity and water saturation (the inverse of hydrocarbon saturation) and possibly reservoir characteristics if they run an image log. I would also take rotary side wall cores and run an MDT which would provide physical rock samples of the reservior and obtain downhole reservoir pressure, sample reservoir fluids plus possibly mobility. All this data could be integrated into the existing reservoir model and reservoir simulation model. The amount of available well data and the field production history will be compelling to the Independent Auditor such that a test of the well would not be necessary . If it was me I would have checked with the auditor (prior to completing the well plan) that a test will not have been necessary. I imagine that Carnarvon have already done this and are acquiring the data they will need to satisfy the auditor. The auditor will work under the SPE (Society of Petroleum Engineers) guidelines which I am pretty sure allows the auditor to certify the reserves based on the total evidence presented.
With regard to financing I am confident that Advance is talking about Reserve Based Lending (RBL). There are banks in Singapore and Australia who would take this on as well as at least four of the trading companies who want the oil for trading or as refinery feedstock. Typically for new production the offtaker would pay a discount to the first cargo until they had done an oil assay. It is simple to allow for this - just remove the crude premium for the first cargo.
Q2 Availability of leased equipment
I am pretty sure the preferred option is a MOPU (Production Jack-up) of which I know there are a number of units available in Singapore. They will need a Proven Reserve report to lease the equipment and Canarvon as Operator will have to furnish a parent company guarantee which is likely to be back-to-back with a joint and serveral agreement with Advance. No problem for Carnarvon because of their market cap. My point is I would be more comfortable when they have secured at least an option on a production unit. I wouldn't dismiss the possibility of using an FPSO although they can be a little tricky (and costly) to upgrade if they don't exactly meet the field characteristics. An FSO (Floating Storage and Offtake vessel) should be easy to find
@ShareInvestment. Why do I expect a positive outcome?
In a nutshell the depth of data available and my personal experience. The Buffalo field benefits from two huge advantages, an abundance of well data and 3D seismic. The well data provides unequivocal production data and reservoir penetrations while the 3D seismic provides the imagery. I have been involved in similar 3D seismic reprocessing projects (including having a steep carbonate flank on the seabed which distorts the seismic ray paths) and also with field developments which are identical in their development philosophy of using leased production units and floating storage. I have also worked on/ or assessed projects which have been audited by RISC and am comfortable with the CPR which they have produced. So I understand the technical data (including the jargon) and so can assess the technical risk.
I think the two main technical risks are:
The top of the reservoir being deeper than the current seismic interpretation. The interpretation could be off by a leg on the seismic or the velocity model could be slightly wrong. The lower the top of the reservoir, the lower the rock volume under closure and the lower the in-place oil
The net reservoir within the structure is different to that modeled, it could increase of course, but it could also decrease.
RISK have assessed these risk, I have not seen he raw data so will have to defer to them on this. I'm slightly uncomfortable with their extremely favourable risk assessment but can understand how they have got it.
My view is that had the previous Operator had been able to reprocess the 3D seismic in the way it has been done now, they would also be classing Buffalo-10 as a low risk development/appraisal well. The commercial keys to the project are:
a) Being able to get the Australian fiscal terms under a PSC contract in Timor Leste and
b) The high flow rates and high recovery per well
c) The current high oil price environment.
d) The low Capex and the availability of leased equipment.
Timor Gap (the Timor Leste national oil company) have a good relationship with Carnarvon and are very supportive of the development so the sovereign risk is very low.
Other risks are -
- Execution, Carnarvon are not typically an oil field operator and prefer to be prospect developer. A lot of this experience can be brought in and as usual the project leadership is the key.
- Closing Project finance. There are a number of oil offtakers who will be keen to get their hands on the volumes for their trading portfolio. However, they will need to see an updated CPR and this will take time. This is one of the reasons why I think production will slip to early 2024. Installation of equipment would then fall withing the tropical cyclone season, which could increase costs.
I hope this helps, please remember this is not a recommendation, but hopefully will be additional information that you can add to your resear
@AJ1409. The diagram of the attic which has been put up by Carnarvon is NOT to scale. The top of the reservoir in the new seismic interpretation is at 3200 meters TVDSS the original field wide OWC (Oil/Water Contact) is at 3316 meters TVDSS (as per the CPR). That makes a total oil column height of 106 meters. The oil has been produced to a depth of the top perforations of Buffalo-7 which is estimated to be 3267.6 meters TVDSS. Thus, approx 48.4 meters of oil column has been produced leaving a prospective 67.6 meters of oil column at Buffalo-10. This is what the seismic interpretation is forecasting, the reality will be established by the drillbit.
As far as when the target reservoir is reached, this is what I estimate from Carnarvon's/Advance's statements to date. The rig contract is for 35 days. Approximately 5 of those days have been used getting on location, jacking the rig up and onboarding all the materials and equipment. No spud date has been given but lets assume if was the 30th Jan (the day before the press release). That leaves 30 days. The well will take 7 days to complete and suspend and so by the 23rd drilling day the well should have reached TD and wireline logging completed. Based on this I would expect a reservoir penetration and drilling to TD around the 19th to 21st Jan. Maybe an RNS would be released on Friday the 21st or Monday 24th. Sometime around there anyway. Of course this assumes that the well progresses as planned. Its unlikely to be drilled faster than planned and could take a few days longer. Don't panic if there is no immediate announcement, news will come out when it of significance. Announcements need to material in nature. However, what is considered material is up to the operator. Maybe they will announce when the well reaches the 12 1/4" hole TD at 2800 meters where they set 9 5/8" casing.
There are a number of posts here that I can offer some comment or insight. I did not work for Dug, rather I have used than as seismic processing contractor before, they have an excellent technical background and have thrown research grade computing power at the seismic and used state-of-the-art seismic processing techniques. The difference in the product is like comparing the original animations in Disney movies with Avatar. BHP simply did not have this capability and made field interpretations from fuzzy imagery. RISC will have assessed this in their independent report. The Oil Voice article referenced by Laohamutuk is a really poor piece of technical? journalism with the only credible person referenced being Peter Strachan who is a well know resource analyst. Laohamutuk is an organisation from East Timor who are not satisfied with the way that their country is managed by their Ministers and politicians. I give no credibility to the Oil Voice article at all. The risks have been very well covered by the Independent experts report and I would recommend reading that.
Q "What has always niggled me is why the attic wasn't originally the primary drilling target?" The answer to this is simple, they could not map it from the poor quality seismic which they had and so they did not see it.
"The question I have is, has anyone seen a pictorial illustration of the B10 and what depth is the attic."
A good pictorial illustration can be found on the second page of the Carnarvon release of the 31st Jan.
https://www.carnarvon.com.au/wp-content/uploads/2021/12/b10drill.pdf
The top of the reservoir target (according to the seismic mapping) is 3200 meters TVDSS (True Vertical Depth Sub Sea). Seismic mapping is always measured from the seabed. Water depth is 30 meters and there will be an air-gap to make sure that any "weather" passes underneath the rig. That's likely to be around 4 - 5 meters. So top of the reservoir in drilling depth should be around 3235 meters. This would be annotated as MD (or Measured Depth from the drilling reference of the drill floor.
The Oil-Water contact which has been used in the CPR is at the Top perforations of the Buffalo-7 well. This appears to be 10,708.66 feet or 3267.6 meters TVDSS. So the expected oil column in the attic is 67.6 meters (using the TVDSS measures). I assume this is the RISC best case.
I doubt we will get an update half way through the attic as it will be all drilled in less than a day.
Hope this helps, GL all.
Sorry Dan, I was too busy multi-tasking: replying to your questions, finishing off my in-depth commercial assessment of Buffalo (to the decimal point) topping up on my Carnarvon shares and researching 88energy that I missed that a new thread had been started for the spud :-)
I do read all the posts, fortunately this board is better behaved than some of the others that I read.
GL everyone.
@ danlowence, quick answers below:
Q have you been a member before under a different name?
No
Q Do you have a holding in this share?
Yes and in Carnarvon
Q You have knowledge of the area, having worked there, in what capacity?
Yes I have knowledge of the area. 4 decades of upstream O&G experience in various senior
roles from technical through operational and management.
I'm not going to give any investment advice (DYOR for that) but happy to help out with any of the technical or operational information.