In terms of non-Russian technology there are two systems in use that can replicate what our Russian Colleagues have done in the past: The Mudline suspension technology and the liner tie-back technology.
Sometimes the Russians used their own technology, a few times technology from suppliers like Austrian Canada Works and similares, who have blueprints of some not so used equipment. May be looking closely at the dates, we could see what was the probable source of the design & equipment used.
Simon,
You are so right. The main KPI during USSR time was the total depth of all well drilled. Drilling Contractors were focused on three things: faster, faster, faster. It is quite a scenario, that the folks of the John's well (s) have used just whatever they had currently on the well cluster and other casing was shipped later. Nobody was thinking about standby rate at that time. On the other hand, one of the KPI's of bigger oil company was the CapEX of the well construction. And one of the component of this cost was the tonnage of casing string. It is really strange nowadays but at that time a complicated tappered string looked having better economics than a straight bigger OD casing string just due to the weight.
I do not think that the old wells of John had BTC connections. Even in 2000's, in Russia, I saw tool joints coming to supply base separately from casing pipes to be welded right on the wells later.
Hi John
I don't have any insight into the Russian techniques, however I would observe that its possible to rotate in BTC casing connections downhole and then get a successful cement job and pressure test.
I have seen this on 2 wells in my time, due to casings which backed out and fell downhole while running due to poor rig floor makeup practices on BTC connections. In both cases the rig just RIH and carefully rotated in the backed out connection. One was 9 5/8" casing, one was 13 3/8" . (Of course I don't recommend it as a standard practice, but its possible).
A basic CCL/caliper log should show if there are just standard casing joints / pup joints in the downhole connection area, or if there is more complex tooling?
I worked with some Russian DSVs for a brief spell in the early 1990s, their main observation for European operations was amazement at how the tangibles and equipment was so readily procured and available. Underlying issue may have been inability to get crossovers made, or limitations on derrick capacity preventing running the full length casing string. (The Russian DSVs I met were all very strong practical drilling engineers).
Regards
Simon Lucas
John,
I am not surprised with this well design. I am a Russian drilling engineer with the experience drilling & workover in the Caspian sea. In the time of planning economy and Soviet specific KPI's for well construction there was quite a number of unorthodox engineering and site solutions. I would strongly recommend you to look at the time lag between two sections of the tapered casing string. Also, please, mind potential lost-in-translation situation. Even Russian oilfield terminology changes may affect the quality of the information you have in your hands. I would be interested to help you with your challenges and I guess the best way to start is to look at the originals of the well design, drilling program, well report. Please, check with your Russian speaking colleagues if they can find ГТН (геолого-технологический наряд). You will be surprised but in Russia there are still manufacturers fabricating the equipment for workover and decommissioning operations designed for old-school Soviet wells.
John,
Drop me a mail direct mate, got a couple of ideas/thoughts, would also be worth you reaching out to your contacts at OMV Petrom as they also did similar in their offshore field.
sounds like a great challenge, similar to what i found in Majnoon, with a surprise every day due to inaccuracy of data.
GD
