For the vast majority of drilling operations, a driller cannot tell you where each tool joint, stabiliser, motors, collars, hvwt and other non-shearables (250-500 tooljoints) is in relation to all the rams, annulars etc, 8 different positions in the stack at any point in time.
They have to stop and locate them.....then verify against the paperwork.
When the bushings flew out of the well, and the TDS landed in the company mans office, do you think he turned around and looked at your spreadsheet?
Spreadsheets are what is killing this industry.
The driller needs a real time display, in cyberbase, that shows a tooljoint in relation to all his rams as they pass through the stack. This is achievable, it is something that drillers have asked for for years.
"When the bushings flew out of the well"
If you're referring to the "bushing" it never was in the well...
Look. Can yall just stop it with the stupid dick measuring contest and get back to the tech discussion?
Real time monitoring would be great, BUT, it looks to me that their tool joint had been spaced correctly for circulating, does anyone come up with different numbers?
Thanks Alf, I was sitting here scratching my head thinking, gee, how can a driller possibly not know critical information about his drill string, such as where to place it so to not grab on a joint, etc.? The answer is, he can't not know. At least using a spreadsheet, and yeah, I could make one that would do it in about five minutes. That said, I'm surprised that the procedure isn't somehow automated, and that the entire drilling procedure isn't automated for safety, to increase productivity and to reduce labor costs. Certainly it will be soon, check this video out of an automated cpt pushing machine.
Automated CPt rig
And speaking of writing things down on a form in an aluminum clipboard. How are things like critical pressures, pump volumes, etc. recorded and displayed? Is the lack of proper display of this information a potential contributing factor to the blow out?
"and that the entire drilling procedure isn't automated for safety, to increase productivity and to reduce labor costs."
** on it since about 1930
Hearing video from Kenner La last Friday.
What jumped out at me during the testimony of the BP well design engineer was a question that Halliburton asked him. Halliburton designed the cement job on that last section of casing to have 21 centralizers. How many centralizers did BP use in that last section? His answer was 6. So, my question is wouldn't a cement bond log have been particularly useful to have before displacing to sea water, since they had gone with so few centralizers?
If we can use an ROV to cut riser in 5000 feet of water the drill string calculator display should be a breeze.