Posted 05.09.2019 13:15 by Magnus Tvedt
Drilling down to 4500m into Jura formations, means they are heading for Heather and / or Draupne sands. According to this report, they are drilling into a Heather shale at 4700 m. And they are planning to do a full casing design. Oh, and this is high pressure (800 bar?) and high temperature (150C+) drilling. But since this is a virgin area, that shouldn't cause any extra problems.
2/7-2 was drilled the same year the founder of Pro Well Plan was born, and is in the same play and reservoir. So that is the closest and most relevant geologic well.
Using 2/7-2 to look for other similar wells, we find many good candidates for stratigraphic similarity, with a spread of geograpic position as can be seen below:
Most similar wells, list view
Stratigraphic similar wells
Map view of most similar wells (pink)This gives us a pretty broad list of wells to review in terms of geology.
The Draupne formation has a large extension across the NCS, giving lots of opportunities for experience transfer:
Wells with Draupne (white dots)
The Draupne formation is most frequently found around 3000 m, but there are more than fifty wells which are relevant in terms of depth. Sorry about the low quality graphics here, just wanted to make a case that there are really quite a lot of experience to be extracted from the data, considering Draupne fm.
Top Draupne fm (TVD) NCS
So before we start analysing the well design, we can say there are plenty of data and wells to learn from, and reading a few specific final well reports will not give you the big picture.
I couldn't find good logs for deeper sections of the well, but it seems that Rogaland Group has been a slow burner for ROP, but that doesn't necessarily impact the overall time too much.
The big drivers of non productive time and significant drilling problems are systemic and predictable events and random operational events. The systemic problems are a function of the well planning data, geology, casings, mud weights and drilling parameters. The random events come from the management structure on the rig which needs an upgrade to be able to handle the complex operations.
So to cut time and costs in wells, we need to plan better so we can optimize without comprimizing safety. And we need to improve the real time decision making based on these plans.
Let's have a look at the well design:
Among the 17 wells we picked as similar references for geology, none of them have a simplified casing design. There is one variation with a 14" and 9 7/8", other than that, they are all in the standard catalog. (25/2-12 has a 4 1/2" sidetrack down deep, but that was for exploration reasons)
Looking at where they have set the casings, there are a few variations of a common theme. Most wells have the 9 5/8" shoe around the bottom of the Shetland Group (including drilling into Cromer Knoll), but the 13 3/8" setting depth varies between 1000-2500m.
And busy Cromer Knoll
I won't spend time going deeper into reasons why picking one over the other, but what about a quick search for incidents in the reference wells? 15-3/9 got stuck in the Ty formation, 25/2-12 got stuck entering the Vestland Group. 25/2-13 got stuck in the shallow sections, probably a random event.
The upper part of the well shouldn't bring too many challenges, the 25/7-2 well (closest neighbor to our well) was drilled with higher mud weights than many other wells in our reference group. Where most wells are at 1.2 - 1.3 sg at 3500m, 7-2 was up to 1.4sg. And it is reported that it was drilled with Water Based mud, really?
High Pressures. What's the margin with that LOT in 7-2?
Of the wells drilled in the basin between Bøyla and Grane, its a tie between oil based and water based muds. I cant see any obvious reason why ConocoPhillips would go for the messier oil based systems.
What catch my attention is the LOT reported at 1.96sg in the Cromer Knoll group. If they were drilling with kick margin in that well, they must have had a significant over balance to the reservoir. Because a kick with 1.95 sg mud and a 1.96sg LOT 1000 meter up is not going to hold. Other wells have 2.05sg and 2.13sg LOT's in the same formations, so it could be erroneuous reporting.
Some other wells have done multiple pressure tests in the deeper formations, but only one well have done a test in Vestland group. That test was at 1.77sg, but they drilled with 2.02sg. 🤔
My best guess is that ConocoPhillips are copying the design from 7/2. That was a well drilled in more than a 100 days and probably cost a foot and an arm.
In fact, looking at the report mentioned earlier, CP have reported they are planning the well almost exactly as the 7/2 well, but the planned mud weights are much lower for the 8 1/2" section, with 1.74sg.
We let you analyze wells and plan more efficiently than ever before. Moving from 3-5 offset wells to hundreds, you can find reference wells for all decisions you make in for and under operations. You as a manager can rest assured that everything is covered, you know when you are taking risk, and you know when you are safe.
We give everyone the same and updated dataset, so the engineers don't have to spend time collecting and fixing data points. That's slaying weeks of dull work and replacing it with exciting improvements.
This review is written based on public data which is available through our platform and interpretations are only the view of Pro Well Plan.
Deep well with high pressure and high temperature well in a fairly straight forward play which has been drilled before.
It seems like they are using the closest wells as reference and copy the design, except for a lighter fluid in the reservoir section.
And I wonder why we copy the previous design, 40 years later.
We can continue the analysis of the well to get more insight on challenges and limitations of the well design, let us know what you would like to hear about.