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Torque at drill bit
05 March 2018
Spread Community, particularly drill bit experts:

 I would like to know what the likely torque is directly at the drill bit when drilling a hard formation with a 8½" and 12¼" PDC drill bit, not the surface torque, nor the torque at the top of the BHA, just the torque required by the drill bit itself.

Obviously, there are numerous PDC drill bit designs and types where this drill bit torque requirement is different, but I am looking for the range that the torque might be.

Is it 100's of ft/lbs, or a few 1000's of ft/lbs, it's obviously not 10,000's of ft/lbs or we could not use them on top of what it takes to turn the drill pipe and BHA as well.

If you have any specific data with bit type and formation type it would be great to have that.

Also, if you know the above, do you know how much it differs for reaming through a hard formation rather than drilling 100% of the hole diameter.

Thanks in advance for your input.
5 answer(s)
Principal Well Engineer
WellPerform Aps
Total Posts: 6
Join Date: 17/05/13
Hello Paul,

I have used WellPlan's torque/drag top-down analysis mode to calibrate/determine bit torque.

Input surface parameters like hook load and surface torque.....string and bit torque values can be generated.

A good calibrated model (friction, mud rheology etc. etc.) either from current or offset/analogue well is required.....and you will be able to get fairly reasonable output.

Torque sensor @ bit is another option to get the info. real time :-)

Cheers. Sandeep
Drilling tech advisor
Franks International
Total Posts: 13
Join Date: 13/03/14
For drilling simulations we have been using torque at bit around 3-5kftlbs for the 12.25" PDC bits and then around 1-3kftlbs for the 8.5" PDC bits; obviously if you have depth of cut limiters on the bit then the TQ goes down and should be smoother. Instantaneous TQ might be high and fluctuating across the bit face if the PDC is allowed to penetrate more or you have 'bit tilt', but this will come out as bit generated stick-slip which is not good for the rest of the BHA.

General Manager
Total Posts: 8
Join Date: 27/02/16
Hello Paul

It can be any figures up to the most powerfull (Low Speed Hi Torque) down hole motor recommended output torque capability (or 80% of the max delta pressure on/off bottom the motor can take) for the hole size application. Not rare to deliver 5000-7500 lbf.ft torque at bit if the motor was well selected for the application (ROP optimization).

DrillScan Europe
Directional Driller
Total Posts: 126
Join Date: 27/02/08

Here are a few ramblings to give my take on the bit/torque reaction thing,

When you approach bottom just before touching bottom is the best time to get a “benchmark” for the system (less bit torque).

As the bit touches bottom, first of all the most important variable is string RPM as this translates to cutter speed. Any cutter needs a dwell time to apply weight, fracture the formation and start the beginning of the “furrow” into the formation. The slower the speed (generally) the more time to develop the formation fail and the deeper the furrow. I think bit people would call this crack initiation and crack propagation.

Once the initial contact is made, then Weight on Bit becomes important as this is the parameter that governs depth of cut. Deeper cut exposes more of the “wall” ahead of the cutter and so requires more torque to progress. Now the fancy bit design elements such as chip breakers, rake angles etc come into play and the subject of cutter efficiency becomes a whole new topic of discussion.

So in a nutshell, I would say that the torque demand from a given bit in a given situation is dependent upon a host of variables. When I model in Torque and Drag programs I normally include a bit torque of 1000 ft/lbs. There is no magic formula behind this figure, it merely gives me a figure to start with. Once actual drilling for a specific bit/formation is underway the daily reports give me actual data and allow me to calibrate the model more realistically (notice the use of the word realistically as opposed to accurately, as in any given situation there will be a certain amount of masking effect from the drill-string dynamics).

As for reaming, this also demands torque but the cutters here are doing work that is out with their initial design spec. For this reason when reaming, I always like to maximise on flow (to maximise the cooling effects of the cutters), and reduce RPM (minimise friction effects of a higher cutter speed).

Again in a reaming situation the torque demand is the product of a lot of variables. A hard formation, for example, may tend to fracture (due to its brittle nature) and fail ahead of the PDC cutter.

Reaming would typically be less torque than drilling (simply because the volume of rock being encountered is less), but the torque “signature” could be completely different with reaming producing more cyclic and erratic torque from the bit.

For further reading, I would suggest;



JCPT paper 2007-082

Consultant [retired Shell staff]
Total Posts: 234
Join Date: 02/09/05

I can give you but an indirect answer. Have you tried the API Diamond bit make up torque work group?.

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