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Hole cleaning in 12-1/4" section with PDM BHA
13 April 2015
What is recommended hole cleaning practices for 12-1/4" hole when using  8"PDM with 1.83 AKO maximum book RPM is 60.
Using OBM, drilling section from 40 to deg inc to 90 deg inc with up to 7deg DLS? 
5 answer(s)
Training specialist - instructor
Nabors Drilling
Total Posts: 7
Join Date: 23/03/14
May be you are drilling through a depleted formation or may be after stop pumping the cuttings will back down making BHP increase causing the loss especially if there is no big margin between BHP and Formation Pressure.
And as you are drilling horizontally the effect of deposition of cuttings on the bottom of the horizontal part of the hole.
Director Engineering
Merlin ERD Limited
Total Posts: 40
Join Date: 20/02/09


Hole cleaning and the minimum requirements to achieve this are well documented and proven from field experience and research. High angle (>30 deg inc) sections requires drill-string rotation and flow above certain minimum thresholds. For your application ”œ12.25in hole, OBM, 40 deg inc to 90 deg inc” these thresholds are:

  1. Min string rotary speed 120 rpm, preferred 150 - 180 rpm
  2. Min flowrate: 800 gpm, preferred 1000 gpm
  3. Mud rheology @6 range 13 to 18 (1.1 - 1.5 x hole size in inches)

The 1.83 deg bend limits string rotation to 60 rpm, thus hole cleaning will be sub-optimal and should be highlighted as a high-high risk (high risk of problem, high risk of severe consequence). Assuming that you can´t change the BHA what are you going to do? Options include adding bladed DP; one jnt per std approx, which provides cuttings transport at lower string rpms. Assuming that this isn´t possible, lets assess the risk:

I´m guessing that you have around 250m to drill (BUR 7 deg/30m; 40 deg to 90 deg = 220m)

  • BHA 8in LWD-DCs etc may be 100m
  • Thus 150m of hole at inc 40 deg to 70 deg.


  1. Maximise flow above 800 gpm
  2. run upper end of mud 6 rpm i.e. 16 - 18
  3. clean-up at TD (max rpm & gpm)
  4. track drag predicted Vs actual (especially on TOOH)
  5. TOOH on elevators (avoid risks of back-reaming - you won´t see cuttings beds & potentially damaging pack-offs until too late)

It´s a short section, so you should be OK, however you´d want to revise the BHA for future wells to remove the associated hole cleaning risks, especially if high angle sections are longer (including casing).

Sorry for the late reply, you may already have drilled it! Happy to share more of the best in class relevant practices from record ERD wells as interest demands.

Iain Hutchison

Engineering Director

Merlin ERD Ltd

Drilling Specialist/Well Engineer/Training Consultant
Total Posts: 339
Join Date: 10/01/05


The latent cause of any hole cleaning problem for me as I stated, remains multi faceted. e.g.

- physical (the well formations, characteristics, the bit, bha, mechanical, fluid interactions etc.)

- in the paperwork (operating instructions, risk assessments management of change conducted)

- the people 'human factors' (why people do, did, what they did, what were they thinking, why was this so?)

Thus there are always several factors to be resolved in such incidences where it is important to avoid assigning blame to anyone or any particular singular aspect. The drilling team has failed where everyone should accept their part in this failure vs pointing fingers.

So waiting to get to TD and a revised clean up cycle as you suggest? I don't see for me, how this solves the problem when, fact is that the problem started many hours or days before?.
In the past, we were educated and developed to get to be skilled and experienced enough to 'listen to the hole' and deal with a problem when the warning sign(s) were first recognised.

As Drilling teams today have far more downhole technology, better mud, tools, equipment than we ever had. How did I miss the warning signs (yes plural) would be the first question I would ask myself.

Then analyse the data, discuss a 'change plan', dynamic risk assessment, and identify what needs to be changed there and then. Waiting to get to TD we were always told being a far riskier strategy!

In this particular case (looking at myself and the facts provided) the numbers also still don't add up. e.g. On a trip out, I can't explain how a wellbore cannot be cleaned at a shallower depth and lesser angle, yet the wellbore has (fact) been tripped through much higher angles where it is far harder to clean yet where the apparent problem (re-ground cuttings) was not identified as we should have been dragging these along the section? Where often no matter how long you circulate on bottom will not often in my view solve this problem.

So how do I explain a reworked cuttings problem shallower and not deeper? unless there is a completely different problem that created a cuttings build up at the shallower point in the well. i.e. a likely wellbore enlargement, (how was this caused now needing to be resolved and discussed for next wells) that then became filled with reworked drilled cuttings. 

This was not recognised, analysed or identified by the drilling team, otherwise on trip out, best practise considered would be to engage the pumps a few stands earlier, pump out and through this section with caution, monitor drag and if we saw further problems then decide if a further bottoms up was needed from this point. note: Often we simply wash the string through these events avoiding rotation first, 'dick around a bit' without having to resort to much 'dicking around'. In worst case we may have to resort to backreaming through this section, circulate a bottoms up, and then continue to POH once clear.
NDSV / DD Coordinator
Total Posts: 4
Join Date: 19/05/14
Thank you for your reply and good information, also the attachments you provided. Mechanism for stuck pipe has now been identified as poor hole cleaning practice during Trip OOH, which was compounded by frequent pump failures. The coincidence of the 2 sticking points being at same inc and azimuth but different TVD's gave rise to the theory of tectonic stress and geomechanic issue, however we have now confirmed that no cavings were evident, just large amounts of reworked cuttings. We will review our tripping procedures and give greater emphasis to clean up cycles prior to POOH. 
Once again, thank you for your input.
Drilling Specialist/Well Engineer/Training Consultant
Total Posts: 339
Join Date: 10/01/05


This is generally the classic ballbreaker section where most historic problems have resulted. i.e. 12 1/4" 30 to 90deg (horizontal) through long clay (deeper then shale), inter-bedded sections.

Rule no 1: go back several steps. recognise and analyse everything planned, engineered, right down to bit/bha design, stabiliser placement etc etc e.g. 7deg doglegs (on some wells) may be biting off more than you can safely achieve!

However there is potential and evident 'pit falls' within the information you have provided.

60rpm rotary? ( vs. don't drill a hole faster than you can clean it?)

note: once angle builds and section deepens ROP capabilities reduce. This needs to be understood and managed otherwise problems will result later.

1.83bent sub (7deg may be the capability, on stringers in inter-bedded sequences etc, this could be much higher, especially with aggressive PDC bits, we have seen this in the past. Note: you generally then don't see this as a wellbore deteriorations problem till you POOH on trips and then through further misunderstood and bad stinger, drilling, tripping practices etc, strings often get stuck via the domino of bad causes and effects that result.)

Note: Commonly several things lead to getting stuck not just one or two!

OBM (if mud is new and you drill ahead too fast hole cleaning becomes a problem. Managing rheology from start to finish optimal solids control is important.) Sometime ROP has top be controlled till mud rheology builds that can then afford higher ROP.

PDC bit? (If wrong type/design of bit is used you to best suit all formation types, (often one needs to compromise) we end up sliding more than rotating, having other loss of wellbore quality problems in certain formations etc, this is all counterproductive to staying free at lowest risk. You want to spend more time rotating if one can.)

Poor/inadequate Bit bottom hole cleaning; People think OBM is unforgiving, however at higher ROP;s more energy MUST be expended at bit otherwise cuttings get reground, mush is generated at bit, and no matter what flow rate is then used you will not be able to POOH without likely having to resort to working pipe, pumping out of hole and more likely having to resort to backreaming.)

vs 'do the right things', get the drilling and connections 'right first time' evident via POH on elevators.

Pump capability: If you are limited on pump then you are also limited on ROP that changes (reduces) as sections deepen and hole inclination increases.

Mud weight management; Too low instability can result, too high other problems can result. A good geo-mechanics understanding and mud weight plan for drilling and tripping needs to be worked. We generally look at offsets, identify the problems and risks, get a specialist to do a study and then stick to their plan unless we take a time out for safety and manage further risk and change accordingly. Often we will drill with a few points less then increase weight for the trip to try and maintain stress in the hole the same throughout.

In critical sections as identified on trips out we often use the low pump method (simply pulling and pumping to get through these zones with minimal well disturbance.) Then return to POH on elevators.

Hole fragility often in these wells in certain sections is critical, where avoiding rotation (after hole has been drilled) is often the imperative on connections and trips.

vs Rotating all the time and doing far more damage than good (note: this is the most common disagreement I have with DD's. However I'm the DSV to manage all risks and make sure we do the right things and get it right first time.)

Some best practices hole cleaning stuff attached.

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