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How to get weight to the bit in a long, horizontal lateral well?
06 September 2019
I am curious as to how weight on bit is applied in a long horizontal well. I have been involved in extended reach wells and wells with complex well paths, but never been involved with the long horizontal laterals which I have been reading about lately.

When your standard BHA/Drill Collars pass the bend section, the weight of the collars is then transferred to the low side of the hole and do not provide any weight to the bit. Granted, you can reconfigure your drill string to place the collars and heavy weight drillpipe back in the vertical section of the well, but this causes derrick management issues during tripping as well as buckling concerns in the drillstring now below the collars. 
Furthermore, at some point, regardless of the collar weight you have in the vertical section, as the horizontal section is extended, drag would 'eat up' any weight which was efectively transferred through the build up section.

If anyone could give me a 'quick & dirty' tutorial on how weight is transferred to the bit in a long horizontal section it would be greatly appreciated!
2 answer(s)
Jason Lavis
SPREAD Associates
Total Posts: 20
Join Date: 30/10/15
This question was also posted on a different forum, and Tom Kirkman tagged me and asked if I knew anyone who could help. I received a great response from Stewart McGregor who's the Senior ERD Engineer and Technical Development Manager at Merlin ERD.

The answer has been posted there, and I'm pasting it here to help others in the future:

Hi Jason,

Hope this is what your poster is looking for. Let me know if there’s follow up required. It’s more high level, rather than an explanation on torque, drag and hydraulics.

There’s no magic bullet to the drilling of the really long wells and no downhole tractors for drilling (yet – but they are in development), only a process of detailed data analysis, optimization and close management during operations.

Some bullet points on specifics. You’ll need:

  • a thorough understanding of the surface loads (torque, drag and hydraulics) which will be imposed before drilling starts and the knowledge your equipment can handle them (and where the risks lie),
  • a wellbore stability model that gives a detailed understanding of the mud weights required (according to the trajectory) to avoid problems with hole collapse and losses,
  • a lithology column which can support the difference between static mud weight and ECD,
  • a high pressure mud circulating systems (7500psi) - probably,
  • rotary steerable systems and optimized drill bits - probably,
  • drill pipe sized for connection torque requirements, buckling, ECD and hydraulics management,
  • light weight BHA’s to reduce drag as much as possible,
  • mud systems with additives to improve lubricity,
  • a process to understand how clean your hole is while drilling so you can proactively manage hole conditions to avoid drilling and tripping problems in the first place.


The problem that Douglas posed, is actually a cornerstone of the business for MerlinERD who design, deliver horizontal, extended reach, and complex high angle wells. They also run courses to teach others to do the same. You can probably guess what the ERD stands for, but to find out about the Merlin bit, you'd have to hire them or attend a seminar :)

Drilling Supt
Nostrum Oil & Gas
Total Posts: 47
Join Date: 14/11/10
I think you answered your question already.  
My rules for BHA design for extended horizontal wells: 
- do not use DCs in the horizontal section, just the minimum amount of HWDPs you need for acceptable jar impulse and impact. Use as light as possible DP in the horizontal section. The more weight you have to push the more drag you create causing helical buckling in the KO section and by that decreasing available WOB. In case all weight is eaten up by the drag you have to trip and adjust the position of DCs in the vertical part of the well. You can prevent this maybe by planning OBM instead of WBM with less friction or using RSS instead of motor or turbine. Using DP  with less clearance helps as well - i.e. 4'' DP instead of 3 1/2'' DP when drilling 6'' section reduces buckling and increases available WOB. As well hole cleaning gets better with higher achievable flowrates by using 4'' DP.  
For the planning stage it is essential to run depth in/out calculations for buckling because depending on DC and HWDPs position maybe helical buckling will not allow you to apply WOB already before final calculation depth.      


Peter-Joern Palten
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