Member Info for CoMan

findme, yes it would be normal that a company like moduspec would be involved but not sure if that is happening here. I believe the well design does requires the managed pressure drilling package to be available. The rig has used the equipment before but part of it it must have been removed as it's part of the reactivation plan to re-install it. Given that the majority of the equipment would be integrated with the rig and therefore would not have been removed I wouldn't imagine its that big a job to re-instate it.

no problem Interesking, on my previous project we managed to keep an exploration rig similar to the Icemax operational through to completion of the project in July, very challenging in the current environment but with proper quarantine rules in place etc all doable - I'm sure Stena will be doing something similar regarding quarantine before going on the rig.

pageofcups -I'd say it's unlikely that anything on the reactivation programme would prevent Stena stating the rig is ready by 1st November, even if only one BOP is ready then - you only need one for drilling

sorry, not sure why they are changing them but that would make sense although it would be strange not to have existing capacity in the lifeboats to match accommodation POB capability

jim - as far as I know they are installing new Davits

pageofcups - it would be normal to go through a reactivation period to go and work for a new client even if the rig had only been stacked for 6 months although I thought it had been stacked a bit longer than that. The rig has been warm stacked but still requires reactivation, I don't think there is a significant amount of work on any of the drilling related equipment however it would be normal to take at +/- 3 weeks to perform a full maintenance programme on a BOP so that would mean 6 weeks just for BOP work.

the rig reactivation programme is projected t take +/- 60 days, main workshop is life boats (as mentioned) managed pressure drilling re-installtion (equipment required for the Bahamas) and most likely there will be a considerable workscope on getting both BOPs ready. During this time they will also be performing maintenance/testing on all the drilling related equipment. The rig is expected to leave Las Palmas late November.

no interest in getting into a ****ing contest bu this is what you said,

In the event that you do find some (Cos < 30 % rem) then there will be a plan to appraise the full extent of the field, ie appraisal wells (still risky). Once that is done (years down the line from now if you find some,

Tell me if i'm wrong - does that not state that appraisal drilling takes years?

If you were talking about development drilling then that's a different story but make it clear that's what you are talking about.

no, i'm saying it has been done within a year numerous times and it's up to the company involved to decide how they are going to do it within whatever timeframe they deem appropriate

you implied it takes years to appraise a discovery - it does not

'Once that is done (years down the line from now if you find some' - this statement regarding appraisal drilling is simply wrong. I could give numerous examples where oil is found one year, appraised the next then first oil is produced within a couple of years after that

rosannan - as mentioned the company gave an estimate on reserves from the logging data - no idea if P90 reserves subsequently booked or not. They have stated the logs showed good flow potential however they're not going to have accurate rates until a well test is performed on an appraisal well.

the BPC presentation states they estimate 20-25% of the reserves are recoverable and they estimate the recoverable reserves to be 2billion

Starchild,

to answer your questions;

1) Difficult one to answer but to give examples from the last 2 projects I have been involved with over the past 3 years;
- on the 1st project the type of information you mention was announced after the 1st appraisal well. Further appraisal wells were drilled to further evaluate the structure and gather information to help determine the development strategy.
- on the 2nd one the company obtained sufficient information from wireline data on the exploration wells (drilled without well tests) to make the announcement giving a range of +/- 20% on the estimated reserves. Well tests are planned on future appraisal wells which will fine tune the estimates and help define the development programme.
2) Looking at the BPC presentations it seems the 2billion is the recoverable number and that represents something like 20-25% of the oil in situ.

the appraisal programme would most likely depend on the complexity of the Geology and the connectivity of the reservoir within the field. The Forties field in the North sea has produced over 2.5 billion bbls, I believe 5 appraisal wells were drilled there. The Clair field on the West of Shetland has over 5 billion bbls reserves and I think they drilled more than 15 appraisal wells to better understand the more complex geology in that field. However with the advancement in technology it would most likely be possible to appraise these fields with less well had they been undertaking the appraisal programme now.

As Irene states they will perform well testing on appraisal wells, in addition to accurate reservoir properties, potential flow rates etc the pressure build up performed during a well test can also determine the extent of reservoir boundaries and give good indications on connectivity etc

I was involved with a successful exploration project over the past year, 1 appraisal well will be drilled on each of the successful exploration wells we had however these discoveries were significantly smaller than what BPC hope to encounter in the Bahamas

Rossannan - difficult to put a percentage on the success rate as a lot of companies have different approaches to what chance of success they are willing to take on. I believe the chance of success quoted here is around 30% which in my opinion is pretty high - i believe a typical CoS for exploration drilling is more like 10%.

Regarding the discussion on well testing i would be surprised if they are planning a well test on this well, reason being they would have to commit to having all the well test equipment available upfront (provided probably by either schlumberger or Halliburton) and this would incur significant costs when there is no guarantee that they would even do the test - they certainly wouldn't do it in the failure case. It makes much more sense to plan on a well test on a follow up appraisal well when they know they are dealing with success.

They do not need a well test to determine success or otherwise on the well, they can get all the information they need from wireline logs and as stated by IreneKrapp a decision to run a MDT or equivalent tool would be made on what the other logs tell them. There are many versions of this tool in the market now ranging from the more basic tools that would just record pressures and possibly take samples if wanted which are not that expensive to more elaborate tools that use packers to isolate different formations and almost replicate a full well test by allowing an evaluation of the formation's ability to flow, pressure build up after flowing (crucial information) and take samples. These more elaborate tools are very expensive but still a lot cheaper than the cost of a full well test spread and the associated 2 or 3 week rig time required to do a well test.

Starchild,

while performing the wireline logging operation they will most likely take sidewall cores for analysis. They will also run tools that can determine all the petrophysical data required to determine reservoir properties and they will take fluid samples for analysis. While taking pressure points in the lead up to taking the fluid samples they can determine 'mobility' ie the ability for the fluids to flow and the while taking the samples they will get a pretty accurate real time analysis of the fluid quality in terms of viscosity etc. The core analysis will not be required to determine if the well is a success or not, they will use the information to help determine future plans for development etc in the success case. They should also have enough information from the logging data without having to wait for the fluid samples to be analysed before determining if the well is a success to not. In reality they should have a very good understanding if the well is a success or not before the rig completes the plug and abandon phase - you actually need a good understanding of the reservoir to determine exactly how you are going to plug and abandon the well.

So they could make an announcement around the time the rig completes operations as they should have enough information by then.

Chriskerr,
I have heard the Stena drillships are all excellent rigs, i guess you were involved with the Icemx just before it supposedly going to east coast canada which i think was cancelled? I have been involved with the Maersk V rigs in recent years - also excellent rigs and also with 2 BOPs which is a great help. My understanding is they plan on using the MPD system on this well - reason being risk of total losses in the carbonate formation and the MPD system allows them to use pressured mud cap drilling to drill though the section.

Just to add some operational context to Starchild's excellent post;

I have a lot of experience of drilling these types of wells with these types of rigs. I have no knowledge of the actual well design but looking at the stratigraphic column and the timing of 30-45 days (the difference i suspect relates to whether the well is dry or a success).

A typical operational outline would be;

1) Load up with all materials and sail to location, I assume the clock starts when the rig is on location.
2) Position the rig and drill the riserless top hole section. This will involve either jetting in typically +/- 80m of 36" conductor or drilling 36" x 42" hole and then running and cementing the conductor. Then drill 26" hole to typically +/- 800m below the seabed and run and cement either 22" or 20" casing. Depending on whether the conductor is jetted or cemented all this should take +/- 7 days.
3) Run and test BOPs on the wellhead. As the rig is set up for managed pressure drilling (MPD) this involves running and rigging up additional equipment so will probably take +/- 5 days
4) Drill 17.1/2" hole to above the top reservoir and run and cement 13.5/8" casing. They may run some wireline logs before the casing. Approx timing for this could be +/- 5 days.
5) Drill 12.1/4" through the reservoir to well TD. Typically an exploration well would be a vertical hole and based on the quoted target depth of 4,822 metres and the photo on page 11 that is the case here. It may take 7 or 8 days to drill this section depending on ROP and if they need to use the MPD system. As soon as they start drilling through the reservoir they will see the real time logging while drilling (LWD) data and have a very good idea if they are in the success case scenario or not....everyone on the rig will know!
6) Perform wireline logging. In the failure case this may only take 1 or 2 days. In the success case this could take up to 10 days. From what i can see there is no plan to do a drill stem test (DST) to determine reservoir properties and flow rates etc however there are wireline logging tools now available where you can get a lot of this data anyway. It also makes more sense to do a DST on an appraisal well rather than incur significant additional costs on an exploration well to be ready to perform a DST and then not do it. They will know for sure at this stage if it is a success or not and could make an announcement shortly after. On recent projects i have been on the companies have made announcements within a couple of weeks of logging.
7) Plug and abandon the well and recover BOPs. The well will be abandoned whether it is a success or not and take +/- 6 days

BPC have stated the well could be deepened to 5600m which would probably mean running 9.5/8" casing or liner then drilling 8.1/2" hole. I suspect this is what the $5m contingency is for.

All this is based on my experience on similar projects - i have no info on what the actual well plan is.

these ships can typically transit at up to 12knots so 3 weeks would be about right, however actual transit speed may depend on what mobilsation agreements are in the contract and who is paying for the fuel etc

I've just recently bought BPC. I'm involved in the drilling industry so familiar with the type of rig and operations involved. As far as I know the rig is the IceMax and will most likely sail from Gibraltar to Las Palmas mid September to undertake a reactivation/rig acceptance process prior to sailing to the Bahamas.