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Surface Torque maxing out
15 December 2015


Any pointers will be greatly appreciated.

Issue:  Surface rotary torque maxes @ 30,000 ft-lbs  once landed & 2000´ in lateral

Hole size:  8 /2”  DP:  5” #19.5 S-135

Profile:  surf nudge to 6 deg  & bck to vertical”¦KOP ~ 10,000, 10/100 DLS, land  94 deg ~ 11,000, 2-D well, dropping to 92 deg by TD ~ 18000'

Curve & lateral bha:  5 bladed  PDC, Motor (2deg  fxd bend), MWD, DP---OBM

Torque in vertical:  ~16K ft-lbs”¦once we land out torque goes up to ~24K & to ~30K  around 2000´ into lateral.  Off -btm torque~22K

Can we eliminate hole cleaning as torque goes back up when on btm?...could it buckling? it the agressive plan??..any ideas or pointers to check where this excess torque could be coming from?

6 answer(s)
Drilling Consultant
PT Drilling Services
Total Posts: 62
Join Date: 15/09/14
KOP at 10000' and getting up to 94 deg at 11,000' (1000' interval), that is a very aggressive build with 10 DLS, thus I would think that is where most of the torque is coming from,plus the 2 deg bend on the motor. 
1) The 2 deg bend on the motor is not necessary if BHA is only being used for landing. A 0.78 ~ 1.15 deg bend should be sufficient for angle/direction correction. 
2) 5" 19.5 ppf DP is normally make up to max 30k ft-lb and I don't think you can get too much benefit from increasing too much on the TDS torque limit, running the risk of twisting off the pipe, especially with the weight of the string. One recommendation is to use taper string with 5-1/2" DP on top. This will enable you to increase the torque limit.I think some 5" HT pipe enable torque limit to increase to above 40k ft-lb. 
3) As suggested by others, use of the non-rotating stabilizer around the bend (KOP area) might help the situation. 
4) OBM itself is the best lubricant. Not much benefit can be obtained by improve the lubricity of OBM. 
All the best, 

(retired) Well Fluids Team leader
Total Posts: 39
Join Date: 14/06/06
As Ron Clark used to tell me the three most important parameters in hole cleaning are

Pump Rate

Pump Rate

Pump Rate

I see no mention of pump rate - very critical if you havent got a BHA assembly to move your cuttings. 
Principal Well Engineer
British Gas
Total Posts: 2
Join Date: 04/08/15
Hi there

Looking at the well profile it is natural to have such torques with kind of BHA involved. few suggestions:
1. Its agressive plan, try to smooth the well trajectory if possible. With the given depths, you have pleanty of room to make well plan less agreessive and can reduce the DLS.
2. Buckling - run simulations to check this. I am sure if you make your plan less agressive say +/- 3° dls, you would improve greatly. 
3. bha - modify your bha design, use hwdp instead of DC. since this is horizonatl well you will have to accept the truth that string will be alwayd on lowside and you will have great sideforce / well bore contact.
4. 2 deg in motor, can be reduced to 1.15 to 1.5 if your dls requirement goes down.
5. try some lubrication. There are many lubricants avaiable suitable in OBM and conduct lubricity test. This will give you an idea of relative reduction in friction in the lab.
6. you can also try NRDPP (non rotating drill pipe protectors), its the same as suggested by else).
7. if possible increase the torque limit of top drive on the rig.
Hope this helps in your planning.

Total Posts: 11
Join Date: 07/12/15

Luke:  Thanks...The torque limiter is set to we keep backing off params when we hit the limit...good pointers there on considering raising the limit or including some HWs if buckling ..will look into that.

Ian:  Thanks for the pointers...BHA: we did not have any DC or HWDP in bha..however running lightened DP might be an option to think...Geometry change:  seriously looking into this one...plan to be less aggressive on the curve..should have some dh vibration data soon to look into..


Directional Driller
Total Posts: 6
Join Date: 25/08/15
Is your max torque of 30k based on top drive limitations or just what you have set the limiter to?

If your off-bottom torque is 22k and your drilling is generating up to 8k additional downhole TQ with the PDC bit this is not unusual. I'd estimate that 3-5k of that is being generated by the bit and the remainder by the tool joints.

Design software such as Schlumberger Drilling Office or Compass can tell you how much your well trajectory is contributing to torque readings (allows you to enter a downhole torque value)...and will also give you a buckling margin based on your BHA design.

If you have extra headroom available I would simply raise the torque limiter setting. If the lowest make up torque of your BHA is the 8 1/2" bit (made up nominally to ~18k) you could you set your top drive torque limiter to off bottom TQ plus 80% of this value = 36k.

The other consideration in this scenario would be make up torque of your drill pipe to surface. If this is 45k then 80% safety factor would give you a torque limiter setting of 36k. I have run plenty of jobs where tight operating limits meant we had to run a 90% safety margin instead. Ultimately the likelihood of a connection backing out is low.

Other options are running non-rotating protectors such as the attachment, these typically give a reduction in surface torque of 10-15% by helping keep the tooljoints off the lowside. Starglide lubricant added to OBM is popular here in Australia, use at least 2% (1% effect is negligible).

Or consider placing HWDP in the 5-20deg portion of the well to stiffen the BHA for better weight transition if modelling suggests buckling. This may however entail scheduled wiper trips to shuffle HWDP to keep it in the low inclination zones. Best of Luck - Luke.
Documents uploaded by user:
SS3 Non-Rotating Protector_Brochure_2012.pdf
Director Engineering
Merlin ERD Limited
Total Posts: 40
Join Date: 20/02/09

Dear "VC-CS",

We deal with high torque on our ERD wells and where our planning and modelling predicts an issue we work up contingencies. From the very limited info, here's some thoughts:

1. Immediate fixes (you've likely tried these, but I've added for completeness - start simple)

1A.Mud Lubricity: limited gains in OBM, but may get you below, increase oil water ratio or use additive.

1B. WOB, accept a lower WOB if it drillsahead

2. Fixes on the rig

2B. Reduce BHA weight (I don't see any collars, so might not be possible). Use less HWDP?

2C. Switch to tri-cone bit, lower reactive torque

2D. Use lighted DP in HZ section

3. Other investigation areas

I have assumed that Tq is being generated by geometry, friction and weight of drilling string components. It is not uncommon to see a step change in Tq due to vibration. Is there anything to suggest this; previous wells OK, erratic Tq, polished DP?

If vibration is suspected, then it's the usual vary parameters, change contact points, assess stiffness. You may not be able to solve this on the rig, or even this well. It may require some extra design engineering.

There is a little innovative Drilling Tools company in New Zealand, TD Tech, that have some mould on stabilisers for DP that have reduced Tq in their trails. Geoff Murray is behind it and as many of you will know, Geoff designed the Lo-TAD centralisers which became step change enablers reducing drag in ERD wells and (Austoil, bought by Weatherford).

Please confirm where Tq is originating, before jumping to a tool solution. I'd also have a look at you DLS and see if you can reduce sideforce, which is likely adding to parasitic drag.

Give us a call if we can help

Iain Hutchison

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