It is widely known that the drilling fluid´s primary function is to keep well control and prevent an influx of formation fluid to the well causing a blowout. The mud also prevents loss to the formation by keeping the hydrostatical pressure. Not a big issue in the top sections of the well. As we approach the reservoir, however, the consequences of a loss to the formation is critical. The permeability is reduced, and the danger of emulsion is lurking in the dark.
What do you do when you run into a casing connection that is impossible to break out? Do you send a man into the red zone with a reciprocator saw while the string is in the elevator? Or are you willing to spend some time rigging up a belt tong to assist where your roughneck or casing tongs were not able to deliver the required torque?
Hopefully not. We have safer and more efficient ways of handling P&A jobs with obstinate connections.
If you were guaranteed to save 30 hours rig time by investing NOK 250.000 extra - would you do it? Well, someone did and they saved close to NOK 3 million. And got ahead of plan already after drilling the top hole.
In a previous blog we have described the significant potential efficiency gain that lies in a fully automated drilling process, by use of intelligent robots at the drill floor. Before we go into details about how such a system could look, and how we can get there, let’s take a look at where we are on automation on our modern 6th generation rigs today.
The hose is gradually losing its position as the preferred method of filling the casing. No wonder when the modern Fill-Up & circulation tools provides more well control, better assistance in getting to TD and improved safety. In this article I will discuss some of the issues related to optimum use of the tool.
The introduction of the FMS (Flush Mounted Spider) has made a step change in Tubular Running Operations. The increased safety on the rig floor is obvious when compared to the traditional methods of running casing & tubing. And when it comes to heavy-weight strings, the FMS is your best option.
There is always a discussion about where to put the most flow, through the bit or through the hole opener. There are as many points of views on this topic as there are specialist working with top hole drilling.
The question is - when 20% of the opening effect comes from the bit and 80% comes from the hole opener, shouldn't that be reflected in the flow distribution?
It is not science fiction and it is not years ahead of us: The robots are here, they are for real, they are highly intelligent professional drill crew and they are likely to be operating in the North Sea by the end of the year.
A question we're sometimes asked is: Why is drill pipe classified as “Premium” once it has been in the hole, and why is it all of a sudden 20% weaker than new? Well, it’s a bit like buying a new car. Once you have driven it out of the dealers shop, it’s classified as used. In today’s blog post, I’ll focus on the drill pipe body itself and not the connections.
Bonanza! Your petroleum geologists have discovered an oil or gas deposit. Now you just have to get as much up as possible at the lowest possible cost. Part of the procedure is drilling production wells, usually done with the help of templates. Here is a basic introduction to what template drilling is, and why & how we do it.