We have been facilitating a series of DWOPs for dual activity rigs. One of the topics being raised is "to what extent can we prepare logging tools offline?".
On a dual activity rig, there's both a main and an auxiliary (aux) drillfloor, often with enough people to operate both.
We hear it's not uncommon (e.g in Thailand) to M/U logging tools offline, even on conventional rigs, in the mouse-hole and rack back; in a "sock" to prevent bending.
In discussions about using the aux, a concern was the position of the logging sheaves. This pre-supposed that the cable head needs to be attached.
We'd value the experience of members:
1. Are you M/U and rack-back logging tools off-line
- How are you doing it?
- Can you share the detailed procedures with us? (or to [email protected])
- What lessons have you learnt ?
- Are you racking back with cable head connected or not
- Are you using a "sock" - if so what's it made of
2. Are you thinking about it?
I read somewhere .. "those of us who say it's not possible should get out of the way of those who are already doing it"
This just in from a wellsite QA/QC guy (Log Witness) who's a scrappy internet connections, so he's asked me to post it.
How - more than one method I´ve seen
Â· Using casing sock
o Joint of casing placed in the aux well
Â§ This is by far the best way, and avoids excessive tool bending while racked back, especially in heavy seas. There remains the danger tools will still bang around in the sock, but there is less chance of field joints backing off
o Requires special fitted make up plates to be manufactured to allow tool to sit on top of the casing sock
o Length is limited to usually ~32m, so it´s not always possible to connect the full tool string, especially if jars are run. However, with sufficient space on Aux side of well you may be able to connect the remaining tools (telemetry, etc) laid horizontally to the tools in the sock by using jumper cables, and then transfer to a second sock (third sock actually, as second will be used for run 2). See below
o For larger strings such as MDT / RCI, a second sock can be used and it´s possible to check those modules in the socks.
Â§ For using a second sock for a single tool string you need to be sure you can connect the two ~30m lengths of strings, and that may depend on how centred your tuggers are, and how the rig is rolling. It may be possible to use the pipe handler to steady the string, but this will only come from experience on a rig.
o Problem I see with using casing sock is that sock / tools are transferred from Aux to main via pipe handling / racking equipment and tools pulled from sock. Although modern logging tools are built to resist a degree of shock, this is still a potentially risky part of the operation for the logging tools, so a proper briefing with rig crew as to how sensitive logging tools are (glass detectors, etc) is very worthwhile.
Â· Make up in Mouse hole and rack back
o Tools are made up in the mouse hole and checked, then racked back in pipe rack until needed.
o Limit is depth of mouse hole, although it may be possible to remove the blank and allow them out the bottom. The risk is dropping the string, and I´ve only ever seen it done with blank in place.
o Problem with this method is that the tools can move around in the pipe rack, and it has been known for field joints to back off.
Method - for a typical run 1 Petro, run 2, petro / image, run 3 MDT/RCI, run 4 coring, run 5 VSP
Â· First two runs are made up and checked in Aux well, racked back, before wireline rigged up.
Â· Run 1 moved to main, logged and put back in sock 1 and moved to aux or mouse hole
Â· Run 2 moved to main, logged
Â· Run 1 is rigged down offline (after log verifications?)
Â· Run 3 is rigged up offline. May or may not be checked depending on second acquisition system and crewing, and then racked back
Â· Run 2 out of hole, and racked back
Â· Run 3 moved to main and logged
Â· Run 3 out of hole and racked back
Â· Run 4 and 5 usually conventional rig up
Considerations (and some lessons...)
Â· Do not make up tools in either sock or pipe rack too far ahead of time. Even in lightest seas there is still room for movement, which leads to joints backing off and potential for tool damage / failure. We were using a 12 hour maximum which should be plenty of time.
o It is very worthwhile long term to monitor tool failures and note any that could be attributed to vibration. I spoke to a TP on a rig one time where the rig had been using the mouse hole method and they had experienced a lot of tool failures in the past. Unclear if they were racking back related or just poor maintenance in the location
Â· Recommended to still check all connections for tightness as they go through the floor.
Â· If you are racking back first two runs, you will need to ensure the logging contractor has
o Sufficient special c-plates to make up tools and rack them back
o Sufficient common accessories for the first two runs, such as knuckle joints, centraliser, etc
Â· For short strings such as coring tools, conventional rig up is usually quicker.
Â· No point with VSP strings
Â· Make sure run 1 and run 2 are clearly identified and positioned for proper access, or potential for rig crew to move wrong string into the main well exists.......hello....
Â· Where and how to complete after log verifications.
o For some instruments this needs to be competed with tools on deck, so they need to be broken down and made up again.
Â§ Do you do it online in derrick ASAP at surface? This is preferred for me, as you know immediately if you have a suspect instrument / log
Â§ Can you do it in Aux well? See below
Â§ Do you wait and do it after final rig down? At this point you may have a suspect log, and missed the opportunity for a re-run. least preferred.
o If tools moved to Aux, how will tools be powered up for after logs? See below on second acquisition system & third engineer
Â· Second unit / acquisition system
o It is unlikely that checking of third run and after log verifications can be completed on the main unit as engineer will be busy with data management and the second run in hole.
o Either a concurrent acquisition system with a surface line or a second unit / container with an acquisition system fitted should be planned if you want to function check the third run offline.
o If a second acquisition system is not planned, then you can simply make up offline, and then move to main well, and function check on line (~30 mins?)
Â· Crewing needs consideration, and two additional operators should be allowed. Depending on how after log verifications and third run checks are handled, a third engineer may also be required. so consider need for three additional bodies to the normal two crews for a typical success case wireline operation.
Â· Consider a third ”œtop string”. Ie. Swivel, telemetry, gamma-ray, etc. With main and back up rigged up, if tools fail during checks, offline rig up becomes more complicated.
Â· Tool management by wireline crew. With so many tools rigged up at the same time, and possibly three engineers, management of assets is critical to ensure all know what should be rigged up and when, and is actually rigged up.....