Sapan Gai, CCO at Sovereign Metals, discusses their superior graphite test results. Watch the video here.
News is now out on the ASX https://cdn-api.markitdigital.com/apiman-gateway/ASX/asx-research/1.0/file/2924-02472359-6A1071053?access_token=83ff96335c2d45a094df02a206a39ff4
Not sure if anyone can open this link but they have spudded and drilled the first section and set the 30" casing. Drilling 17 1/2" hole section now. Nothing exciting until the 9 5/8" casing is set. Operations were help up by tropical storm(s) which I assume delayed the jacking up of the rig.
@DPYC "What is my expectation/hopes from the results?"
Let me restrict my response to the technical aspects of the Buffalo attic:
The seismic reprocessing was undertaken by a company I have previously worked with (DUGS) and I know it was well QC'd so I have a high confidence in the geophysics . The geological model of the field is well known from the wells as is the production performance. The area I am not so clear about is the reservoir simulation as this can be very complex and dependent upon the input and software used and the person who built the model. However, the history matches for the previous production seem to fit how the field is modeled and the statistical way in which the field has been assessed is a standard way of dealing with the range of outcomes that could occur from the well. I've seen some posts on another bulletin board (ADVFN I think) referencing a binary outcome. A binary outcome has only two outcomes e.g. True False etc . However, because of the variables which are inputs to the modelling, and their ranges, there a range of outcomes from low throgh medium to high. I think I read that 500 iterations had been run. So there are numerous outcomes depending primarily on: the seismic mapping (rock volume), reservoir porosity, net / gross of the reservoir, reservoir pressure, water saturation and the height of the oil column. This is the reason why we drill the well - to get the real data.
So what do I expect?
Based on the technical information I expect a successful result which should be around the 2C outcome. On a purely technical basis, as I haven't seen the full data set, I am uncomfortable with an 85% chance of success but I understand how it was reached and RISC are a professional outfit.
What we will not know from the immediate well results are:
Flow rate of the well -: The well is not going to be tested and no matter what Carnarvon or Advance Energy say the definitive proof of the well performance is via a test. Having said that the data collected (particularly if they take side walls cores) will provide excellent data to revise the reservoir volume.
A definitive field size, and the relative 1C,2C and 3C volumes : The well data will take time to process, evaluate and QC and then the models need to be updated and the information provided to update the CPR (probably by RISC). I would be very surprised if the updated CPR was turned around in under 3 months from the TD of the well.
Another unknown is the recovery factor - this will have to be simulated and the field development plan will have an influence on this. Yes the field could probably flow up to 40,000 bopd but if there is no well redundancy thus losing a well could halve the field production rate. Also if the field is pulled too hard the water could be drawn in quicker (possibly coned) and while water handing capacity could help if the field is produced too quickly the ultimate recovery could be reduced.
That's yesterday's close, ASX not open until 11pm UK time.
@Piltick once the rig is towed to location and surveyed in the legs are lowered to lightly pin the rig on location. One of the tow vessels could be released then. The exact process of jacking down is dictated by the rig owner who will have looked at the site survey and geotechnical info and worked out a sequence of jacking down. The vessels going back and forth to Darwin are picking up the drilling materials (casing, drill water etc) and offloading onto the rig. The rig is a Keppel FELS Mod V so has a reasonable deckload but will need to be resupplied.
Under standard joint operating agreements, the Operator (in this case CVN) will be responsible for the Market releases, they will co-ordinate with Advance but the primary release will come from CVN first. So the release will come out pre-market opening of the ASX. Each company has their own interpretation of what is material. For example a spud of a well for BP would not normally be determined as material whereas it would be for a single project/single well company. In this case I think its likely to be considered as material by CVN.
Currently we are on the equivalent for Summer Holidays for Australia, in normal years the place shuts down for business from around mid-December to end Jan, so if they have completed spud I would not be surprised if the release comes out late.
With regards to the spud. The rig is locating on top of a dead carbonate reef which lies on the seabed. Its this carbonate reef which played havoc with the original seismic and the new 3D reprocessing had to take account of this and ultimately led to the identification of the "attic" at depth. Putting jack-up legs into a dead reef which may have alternating hard and porous layers is of concern for the drilling rig owners as one (or more) of the legs could punch through hard seabed layers and damage the legs. For this reason the jacking-up of the rig is slow and done one leg at a time. All non-essential crew would have been demobed and the hull filled with water at the end to load test the leg penetration and make sure that the seabed can carry the weight of the jack-up and its loaded materials etc. Once the rig company is satisfied the drilling materials (wellhead, casing, cement, mud-materials, fuel, etc) will be loaded and the service crew brought out by chopper. Thus the rig up and spud when changing operators and in different drilling areas can take longer. So no surprise the well start-up takes a little while, that just the way it is. And no, the rig and service crew will not be taking Christmas holidays, they will be on rotation or on standby, offshore drilling operations are just too expensive to be shut down by crew availability. Hope this helps.
For what its worth I thin the well should have spudded by now and we should get a notification of this shortly. The oil is not going anywhere, its still trapped there and everyone will just have to be patient. The Aussie market is usually better informed and the increase in CVN share price probably tells you that operations are moving ahead at Buffalo.
I'm not sure that I understand your question., but I will try to keep this as simple as possible. The volumes in the RISC CPR are for remaining recoverable oil volumes in the Buffalo field which lie within the current field mapping. This assumes that the field wide oil water contact has equalised to 3316m TVD SS and then the volumes (In-place and recoverable) have then been calculated using the "new" field structural maps which include the attic volume identified from the seismic reprocessing. The Low , Mid and High cases for rock volume account for uncertainty in the seismic mapping, variation in reservoir facies within the undrained area and porosity. There has been a lot or reservoir modelling, production history matching and reservoir simulation that has also been used to work out the remaining oil in place and likely recoverable volumes: actually the plan of development, number (and placing) of wells also has an influence in how recoverable reserves are calculated as does the economic cut-off. Just think of the Low, Mid and High cases (1C, 2C and 3C) as statistical outcomes derived from models created from the previous production data and the existing well and seismic database. The CPR will be a summary of Terabytes of data analysis.
I read the MountTeide post on Jadestone and was going to reply to it directly (I still might), but for what it's worth here is my response to that post:
Jadestone and ADV are two completely different beasts as follows:
Management
The Jadestone Management have deep exposure of Operatorship being primarily ex-Talisman. The CEO (Paul Blakely) built a very successful operating business in the North Sea and to a certain extent in Asia-Pacific although a lot of the Asian assets were already in place by the time he arrived in Asia. Leslie by contrast does not have such operating experience, this being his first real C level role. However, Leslie does know how small fields work though from his experience in Thailand which is relevant for Buffalo.
Strategy
Jadestone's strategy is to effect change via operatorship. The flagship asset Montara, was a poisoned chalice when Jadestone acquired it being the Australian equivalent of Macondo. Due to poor operating procedures, the incumbent operator (PTTEP) lost well control during well completion resulting in a blow-out and a fire that destroyed the WHP and rig. This event single-handedly made operating in Australia much more complex. The FPSO when they took it over had multiple safety issues and was shut down for urgent repairs shortly after Jadestone took over. Jadestone eventually navigated through this successfully but they took on a big risk to do this. In New Zealand the transfer of operatorship to them from OMV might never occur because of the failure of Tamarind who took on appraisal risk and failed. Tamarind declared bankruptcy leaving the FPSO stranded on location and the field in abandonment limbo. The NZ government eventually had to foot the bill and now does not want to make a decision of transferring of operatorship to Jadestone for Maari. In Vietnam, there are real challenges in negotiating a gas sales agreement. I point out these issues because it's part and parcel of being an operator and the price you pay for controlling your own destiny. Navigating through these obstacles keeps the company sharp and provides valuable experience (although it does not seem like that when you are sat in the top seat sometimes)
For ADV the strategy is for non-operated interests. Whilst all the operating "baggage" is removed it means that, no matter have good the JV agreements are, you no longer control your own destiny or timetable. It also restricts the dealflow in that it might be a great asset but an incompatible operator.
These are not inconsiderable differences. Jadestone have done a good job to date and present well to the financial community giving them institutional support. The same cannot be said for ADV which have yet to get an institutional following as it's early days for them yet.
Don't get me wrong I like the Buffalo asset and think it has strong technical merit but, in my opinion, the path that ADV will follow will be completely different from that of Ja
@AJ1409 The rig rate is just that, the costs for the daily rental of the rig. It doesn't include consumable supplies (like fuel) or tax for example. However, the daily cost of drilling a well is much, much higher than just the rig rate. When you add on the costs of all the additional equipment, services and consumable supplies required your get the "spread rate". I've detailed the types of services that you have and all the equipment, materials, manpower and service charges (from wireline, cementing, mud engineering etc) plus all the costs of associated infrastructure helicopters, boats (tugs, supply vessels, stand-by vessels) and so on will get you to the spread rate. Wouldn't we just love it if the well cost was only for the rig - for 30 days the well would cost less than 3 million. Sadly, it doesn't work like that. Typically the offshore rates will stay the same 365 days/year although onshore support services may increase in price for call-out work. What you don't want is to have a problem over Christmas or New Year as it is hard to organise the onshore logistics. However, all operators will have contingencies in place for this. Just on your point about drilling on budget. That's just an estimate made by the drilling team, the real cost will depend on how long the operations go on for, Jadestone will know that all too well..........
The Skua field is a sub-sea completed development which is tied-back to the unmanned Montara Well Head Platform (WHP) facilities i.e. there are no permanent surface facilities at Skua. For this reason, the Montara sub-sea wells have to be shut-in when the Skua wells are added or "tied back" to the facilities. The sub-sea tree is a critical piece of safety equipment consiting of highly engineered safety and flow valves that control the flow from the well. It's a stacked series of valves with gauges and control lines coming out of it and resembles a tree. It sounds like some downhole completion equipment failed on the Skua-10 which is the reason for the latest delay.
The shut-in of the Montara sub-sea wells and loss of oil production is a material change that requires a RNS release - thus they saved up all the information about the production milestones and operational delays. No operator wants to air its dirty operational laundry unless it has to. From experience, I would say there is still a few days work left in this. Carnarvon will announce as soon as the rig is ready to transfer to them.
@Barraband the Australian code requirements for the electrical systems require physical changes to meet safety zone requirements and so they are built in to the rig now. There is commonly a dry dock cost for this and this is one of the reason why the rig rates are higher in Australia. The contract rig rates will more than likely be the same as for Australia. This "hybrid" PSC is new to the Timor Gap (the regulatory authority) but given that rigs often cross into their territorial waters from Australia there will be an offshore rig acceptance at or near the maritime boundary. There will be no issue with this as the rig standards will all be compliant because of its work in Australia waters.
Having seen a number of comments on the Rig situation I thought it might help if I explain how it works contractually in the O&G business.
The drilling rig is currently undertaking work-overs on the Skua field. The rig needs to meet Australian code, particularly electrical and safety code which is unique to Australia. This is an additional burden on the rig company which does not have to meet these standards elsewhere in SE Asia and has additional costs. Also there are Australian specific manpower regulations which increase manpower and crewing costs. This increases the rig rates by at least 30% compared to SE Asia (it has been known to be as high as double the rates)). This isn't the only cost as there is of course fuel (this is direct cost to the operator) and numerous additional contractors - helicopters, boats, onshore logistics, wireline services, cementing, mud engineering, mud logging, contracted rig management, weather services, tool rentals, well insurance etc etc. In total there will be +/- 30 separate contracts in place and probable around 100 to 120 people on board the jack-up. I would not be surprised to see a spread-rate (rig and service contractors plus consumables) running at US$ 250 - 300,000 / day. There are considerable well construction material costs, well head, drill bits, casing and appurtenances, cement, mud material, completion equipment etc. There is also onshore management costs, well planning, site surveys, environmental permitting, emergency response, crew change costs, mobilization and demobilization for the rigs, vessels, service equipment etc. Which is why if you divide the well cost by a 30 day program you will reach an expenditure of approximately US$ 666,000 /day. Obviously this is a very simplistic description and there will be different fiscal treatment of the tangible and intangible cost assignments under a PSC regime but you get the general idea.
What Carnarvon will have done is to contract the rig and all the onboard service contractors for an additional well at the end of Jadestone program. This guarantees that the rig and services are available to them at a far better cost than if it was a stand-alone well program. In these kind of contracts there will be no definitive date in which the rig has to be handed over from Jadestone to Carnarvon. It is totally dependent on the performance of the work for Jadestone, this makes sense as you have to leave all the operations safely completed. I can assure you that given the hefty spread rates Jadestone will be very keen to get the rig off to Carnarvon. This is not Carnarvon being inefficient or anything other than delayed operations at Skua.
Given the delay the Buffalo-10 well will not reach the reservoir until January. Which part of January depends on when the date the well is jacked-up on location and spuded. Hope this helps. I have not seen any contracts or been involved with them in any way, but this is standard practice.
Sorry, just to be clearer on this. I would expect that they should be getting a good idea of the accuracy of the seismic processing after they have gone below the Echuca and start hitting the seismic markers below that. Maybe 10 to 14 days after spud? If they are seeing the well coming on prognosis then they will be starting to get excited.
There is thinning of the Top Johnson to Top Echuca Formation observed on seismic above the Buffalo field so I would suggest any seismic marker below this could be used . Given the nature of the seismic reprocessing and adjustments to the velocity maps all the deeper seismic markers should be shallower than those in Buffalo-5 which was a crestal well on the original BHP mapping, although the adjustment is likely to be greater at depth. Having had another look at the maps it looks likely that Buffalo-10 is targeting penetration of the top reservoir (Elang) at 3200 mTVDSS. For comparison Buffalo-5 intersected the top Elang at 3272 mTVDSS. On this basis I would expect the markers to be 72 meters higher. Given that the current OWC is estimated at 3290, this would be a 90 meter column. The RISK uncertainty on the seismic suggests a range of 61 to 121meters of oil column, only drilling will resolve this.
Thanks for this, I had misplaced my copy of the CPR. Yes vertical well drilled with no frills - no coring and no testing. Looking at the seismic maps again the Top Elang reservoir is at 3,200 mTVDSS, so most definitely 3 weeks or slight more to the top reservoir.
I've not listened to what Les Peterkin said in the presentation that you refer to but aI do know something about the Buffalo Field. Once on location it will take weeks (probably at least three) to hit the objective, which is over 2,000 meters sub-sea. A number of hole sections and casing runs will have to be made prior to entering the Elang Reservoir. This is standard safety procedure for the well program as required for drilling approval offshore. Once the reservoir is penetrated they MAY make a press release but most likely they will wait to drill through the entire reservoir section. Following this, they will run wireline logs (they may be running LWD logs, I'm not sure about this). A further press release is likely after logging. Press releases are usually managed by the Operator in consultation with partners . I am not sure if they are going to test the well, there are arguments for and against this, but if they do that will be an additional week at least. I don't see the money in the budget for testing.