Member Info for CoMan

Tiburn, yes, based on the outline well plan that was shown I think on one of the Simon Potter presentations it should take approximately 10 days to get to the 1st reservoir target. It was interesting to hear Leo Koots talk about the mud losses in the offset wells in his presentation that I think Starchild posted a few days ago. That is what you would expect drilling through the carbonate reservoirs that they expect on this well. It's probably also the reason for wanting a rig that has an integrated managed pressure drilling (MPD) package. The MPD package helps manage the well problems associated with drilling these formations. So assuming they are going to have that system completely set up and utilised it would probably add a couple of days overall to the time taken to reach the 1st reservoir.

The outline well plan showed they were drilling a long 12.1/4" hole section through the various target reservoirs, given the comments about mud losses etc in the presentation this is likely to be a very challenging section to drill but the MPD system will help - so I'd be expecting problems drilling this section but I'm sure that is taken into consideration in the estimated time they have in the plan to drill he well.

Tiburn - I have 36 years experience in the oil industry, the majority spent drilling wells with one of the majors but the last 10 years or so with either national oil companies or smaller independent oil companies. I haven't been directly involved with an exploration project where the size of the potential discovery was as big as this could be and mostly the chances of success have been less than the 35% quoted here. So I think there is potentially a very significant upside with Bahamas Petroleum, I'm basically gambling on success with money I can afford to lose.

PI - for the core crews the normal rotation would be 28 days on 28 days off. Additional costs associated with Covid would come from having a lot of the specialist crews (eg wireline logging crew, wellhead engineers etc who would normally only be onboard for specific operations) on the rig a lot longer than necessary. If they have to go down the quarantine route they would be paying people on the rig plus their back to back who is in quarantine at the same time - as opposed to normally only paying for one of them, for the specialist personnel they would be paying time spent in quarantine over and above the time they would normally be paying for them on the rig. If they chose to quarantine crews they also obviously would have hotel costs on top of the above.

Tiburn - on the project that I have been involved with this year our rig continued to operate through all the lockdowns until the initial phase of the project was completed in August - as did many others rigs worldwide. We had strict procedures whereby anyone going to the rig had to quarantine for 2 weeks in a dedicated hotel prior to going to the rig. Everyone was tested around day 10. Obviously it was critical that we avoided getting Covid on the rig. I believe Stena will have some sort of protocols in place at the moment in Las Palmas but probably not as strict as the procedures we had that enabled us to continue to safely operate.

Stena and BHP could put in place similar protocols around quarantine when they start operations which are obviously fairly costly. However the other option they have ,given the length of the project, is to put more or less everyone they need on the rig prior to sailing from Las Palmas and therefor avoid having to do any crew changes in the Bahamas. This would mean crews working a long shift of possibly 60-70 days but I know a lot of people who did that earlier this year and many more that would be willing to do it now especially given the downturn in the industry.

Bottom line is numerous operations safely managed Covid earlier this year and there is no reason why BPC and Stena cannot do so here.

Findme - in the present climate it's not unusual for contracts to be structured such that the rig does not go on day rate until the bit is on the seabed and the rig is ready to spud. So while Stena are deploying and calibrating the transponders to position the rig the spud preparations should be ongoing simultaneously. It would normally take +/- 20 hours to position the rig but with all the other other operations required to get ready for spud, ie offload supply vessels, mix spud mud, rack tubulars, make up BHA etc etc it will probably be +/- 4 days after the rig arrives on location before they are ready to spud. If the contract is structured in this manner then it will save BPC several days of day rate.

I believe the rig is expected to depart Las Palmas around the 22nd or 23rd of November.

page 9 of the BPC presentation talks of there being oil shows in the 5 historic wells. Having oil shows does not mean having oil otherwise they would have stated they had found oil, if that had been the case there is no reason why they would not have been producing it if it was in commercial qualities. I'm not a geologist however my interpretation of having only oil shows is most likely an indication that the oil has passed through the formations but is not there now - probably due to there being no seal above the reservoir. The positive aspect of these oil shows is that it proves a hydrocarbon system - as also stated on page 9.

Starchild- I was lucky enough to escape the UK and be on holiday for the last 2 weeks, back working now so paying bit more attention to what's going on and will be paying a lot more attention to what's going on as we head towards spud

my understanding is the rig will leave the docks around the 22nd and complete DP trials prior to sailing. The rig is capable of getting to the Bahamas in the timeframe mentioned however as Stena will be paying for the fuel it would seem more likely that they will sail at an economical 8 knots as opposed to 10 or 12 knots. So probably looking at around 20 days to the Bahamas, +/- 4 or 5 days to load everything up and prepare to spud so I'd guess spudding around the 19th of December

GarryGraham,

my experience is all in Drilling however from what I know of production using a FPSO in the water death and environment makes perfect sense, produced oil would be pumped from the FPSO to an Oil tanker to be taken to a refinery so what has been quoted seems perfectly logical

normally everyone onboard who has access to the screens on the rig that show the realtime logging while drilling data have to sign a confidentiality agreement. Obviously the BPC team in town will also have realtime access to all that data as will some of the 3rd party service company providers (Halliburton). The logging while drilling tools are placed just above the bit while drilling so very quickly the team will have a good idea what they have drilled and whether it contains oil or water. No matter how hard the company tries to prevent this information getting out it's very difficult to do so. The wireline logging which is performed after the section has been drilled records a lot of the same information but in much more detail with far better resolution so is more accurate - which is why a company would wait until they have that information before making any announcement regarding the success or otherwise of the well.

don't think there will be any news regarding success or otherwise until they have ran the wireline logs at the end of drilling the 12.1/4" section which will most likely be late in january. i guess if they are having operational problems they may issue news relating to that earlier.

they wouldn't be announcing anything at that stage anyway as they still have a long way to complete the well through the various targets.

bynari - thanks for posting this and interesting to see the outline well plan on a slide around +/- 16 minutes into this presentation. This slide shows setting 9.5/8" casing at 4950m and drilling 8.1/2" hole thereafter to 6545m. However based on more recent information and the slide on page 11 of the presentation on the BPC website the plan now seems to be stop at 4822m with the capability to drill to 5600m. If they do stop at 4822m then they won't need to run 9.5/8" casing (unless doing a DST which i doubt) so the well would be significantly cheaper.

Ibiza - to answer your question, based on the well plan shown they should be drilling into teh 1st potential oil zone roughly 10 days after they spud so potentially the end of December.

to answer your question regarding the topics in the article;

1) Rock Cuttings are analysed real time on the rig by the Geologist - cuttings are circulated out the well while drilling and samples collected and analysed continuously
2) Mud logs are constructed from the geologist's interpretation of the rock cuttings, these logs show the formation that has been drilled combined with other parameters such as gas levels in the mud that is circulated while drilling (Mud is required to make sure the hydrostatic pressure in the well is higher than the pressures in the formation to prevent the well flowing out of control, its continuously circulated while drilling and also carries the cuttings out) plus a log of drilling parameters while drilling. They are continuously updated while drilling and a very useful record of what's going on while drilling the well.
3) Analysing core data is likely to take months but is not critical to ascertain if the well is a success or not, the information is more relevant for developing a development strategy in the longer term if the wells a success. I'd be surprised if they core this well, its becoming more normal to core an appraisal well when you know you have success rather than commit additional costs to an exploration well where you may not have success. They have the option to take small sidewall cores while doing the wireline logging.
4) Well logs are obtained from the wireline logging tools that are run in the well, they will be analysed by the geophysicists and geologists before the rig has even completed the abandonment phase after the logs are run. Its normal now to run logging while drilling tools (LWD) in the drill string while drilling so a lot of information regarding rock properties, fluid content etc will be available while drilling and prior to the geologist on the rig actually seeing the samples.
5) DST - these drill stem tests are usually performed to establish further reservoir properties, pressures, flow rates from the well etc. A lot of this information can now be obtained with more advanced wireline logging tools. I'd be surprised if they do a DST on this well, again it makes more sense to do it on an appraisal well where you are pretty sure of success rather than commit high costs to an exploration well and then not require the tools etc to do the DST if it is a failure.
6) Reservoir fluid samples will be taken when running the wireline logging tools, the fluid analyser in these tools coupled with other data obtained while logging (formation permeability, fluid mobility etc) will give them a very good idea of fluid properties. I'm not entirely sure how long it would take to get the full lab analysis on the samples but I very much doubt they would require lab data to know if the well is a success or not - that is not normal. If they do a DST then they would also take samples and also fairly quickly have a good understanding of fluid properties while doing the test -

Starchile,

the presentation states that P1 w location was chosen as it encounters;
'Stacked plays from Upper Jurassic mega bank and reef systems throughout the Lower Cretaceous' which means the well will encounter several targets (ie possible reservoirs which may or may not be connected - logging data would confirm). I'm not sure if the 10 highlighted sections on the diagram on page 11 are targets or just identifying different formation tops - the bottom 2 (ie base Aptian and PTD) most likely show where they plan in stopping drilling, ie a certain amount of metres below the base Aptian so they are not targets. However the presentation also states they have contingency to go deeper so based on what they encounter up to that depth they may believe there is another possible target deeper than this.

the drilling industry is a small world so a lot of info gets shared...The Icemax is expected to sail to the Bahamas last week of November - but obviously still to be officially confirmed

the rig reactivation is expected to be comported by last week in November

seems to me it would be more likely, as Jim has said, to replace the boats to increase POB for Covid reasons, if they were just replacing the existing ones then I doubt they would need to change the Davits given the rig is not that old. On my last project we had to load up a lot of extra personnel to cover the various eventualities that occur while drilling, with Covid it's not possible just to have people fly out to the rig just when you need them due to the quarantine requirements.

onlybpc...thanks, you're welcome. I don't know much about the financials so am on here to try and learn a bit from that side and happy to offer any operational insite when I can

interestking....gut feel I'd say the rig will be ready to leave Las Palmas around the last week of November which would put it in The Bahamas around mid December. They will have to load all the BPC equipment - wellheads, casing, bulk materials for mud and cement, mix mud etc prior to spudding - that's easily 4 or 5 days work. I'd say they could comfortably be ready to spud around a week after arriving on location so getting towards the end of December. This assumes that BPC have the necessary supply vessels to get everything to the location to meet the rig - if not they may sail the rig to somewhere like Port Fourchon in the states 1st to load up then return to location. They also need to hook up the 3rd party containers - mud logging unit, directional unit etc and I'd hope that is being done in Las Palmas as that could be 2 weeks work.

jim...what you say about the POB makes perfect sense