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Drill Collar Shoulder Problem
05 September 2019

We are drilling a well and issuing damages on shoulders of drill collars and bit sub at all trips. Damages have been observed on shoulders and only on drill collars not hwdp, dp etc. We have not yet encountered this problem so far.

We have controlled the tool joint compound, it is what we always use.
Connection cleaning has been also checked.
Tong line gauge has been checked again and again and calibrated.

We have high vibration during drilling and stabilizers mostly pulled out highly under gauge.

What is the reason and how can we solve it?

9 answer(s)
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 502
Join Date: 10/01/05
What is the reason and how can we solve it?

As stated we don't have enough of the well's evidence to solve your failure issues.

We can however share other vibrational problems experienced, what was concluded and what was done to resolve this.

e.g. On an multi exploration well campaign (all vertical wells) we commonly experienced moderate to severe vibrational issues every time we hit harder stringers. Prior to intervention drillers had originally continued to press on with 'orange and red vibrational traffic lights (axial, torsional lateral) of various modes presented, versus picking up off bottom, stepping off the gas and assuring we drilled through these zones as much in the green as was practicable to do so. Note: Often we have to compromise.

Consequential loss/waste that resulted by pressing too hard through these zones before more preventative measures take were:
- Connection problems (higher torquer and drag)
- Micro-doglegs that resulted (you wont see the severity of these,  on your surveys even if you were surveying every 5m) , then create environments for side loads and far more drill string excitation and problems to result. (this one of the evident roots to such problem)
- Stick slips whirl and anti whirl effects then more likely result on the drilling indicators that shall then accelerate and deteriorate bit life BHA component drilling performance etc.
- Problems during trips out (having to resort to backream) as this was the only method the drill string could be negotiated through these (Vertical wells!) often then resulted.  
- Unable to run logs (they hung up at stringer depths where doglegs resulted!)
- In summary days to weeks commonly lost on wells due to several evident failings that exists. e.g.

Root and latent causes.
- Bit/BHA Contracts were poor and inadequate, there was not enough duly suitable and specified equipment afforded to assure optimal bits/BHA were designed engineered and run.
- We often had one bit PDC type to choose from in each wellbore sections, no matter what region or geology the area presented. We had to live with this failing and compromise as best as we could.
- Stabilizers were of a poor and inappropriate design. When we asked for others to be sent to rig we were informed 'not in contract'
- People were unaware of the consequential problems and risk that resulted when pressing too hard through these harder thin zones, with a less than optimal bit/bha, and practices as were being used. 

Prevention and results.
- We modified BHA design and stiffened it up with one more stabilizer. 
- We banned running bladed type stabs as were previously being used.
- We resourced some better smaller nozzles so we could more energy to the bit.
- When stringers were noted drillers were instructed as best as they could to stay in the green and avoid high vibrational modes. What resulted was drillers has to come out of auto drilling mode, pick up off bottom far more frequently, change parameters considerably, often several times trying several combination to do this ie stay in the preferred green-orange limits . 
- Due to failings in bit/bha design we now recognized, we often spent 2-3-4hrs to drill through a 1-2m hard stubborn zone than plough on through it. (e.g. PDC's could drill clay/shale at 10's of m/hr but stopped when hitting far more stubborn stratigraphy).

- End wells result (days/weeks previously lost/waste, with far higher risk of component failure exposure) were now repeatedly saved prevented and mitigated on each well. 

Greater wellbore quality was assured, that when we could drill in the more drillable formations we then in fact drilled much faster than previously, more effectively and efficiently as we had few stick slip whirl issues present and more optimal MSE evident at the bit etc. This readily noted at surface via far smoother torque drag profiles exhibited where bit was often drilling at >ROP with less WOB in the more drillable formations. 
- Connections were generally trouble free. e.g. Drill stand down, Stop rotation, pick up 10-15m, come down several meters, observe normal drag, set slips and make the connection.   
- We tripped out on elevators and 95% of all sections thereafter drilled.
- We often spent 4-5days logging a higher quality wellbore without any logging hang ups or related wellbore issues.

In summary when we experience vibrational effects and resulting consequences e.g. string damage failure in your case. One needs to go back several steps to review all the evidence trails to fully resolve where the root cause(s) and effect(s) and latencies exist. The evidence is there for someone who is suitably skilled to recognise and analyse this. Rarely is there only one root cause to identify in such complex issues.

When learnings are determined and evaluated the process cannot stop there as the hardest part by far is how one then translates and sustains learnings through subsequent project planning, engineering and drill floor well's delivery phase and then on to the following and subsequent wells.

I hope this has provide some food for thought to better address your issues. 

Wishing you success on future wells.  

Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 502
Join Date: 10/01/05

What is the reason and how can we solve it?

What's driving the vibration issues is likely a multiple of reasons. Where despite the facts that you are likely drilling through some very difficult stratigraphy (that forms parts of the physical evidence to fully understand) several other factors (physical (components parts) people and paper evidence trails) exist that are not evidently being addressed.

Your teams have all the evident data so in truth only people involved or who have access to all the evidence can resolve this. 
Where once duly investigated. You have likely several corrective actions needed (physical (parts) people and paperwork involved) that would result from a due and diligent investigation into all such matters,  (to then assign to those responsible the who when and how needed) to prevent recurrence.  

How to resolve it? 

Persons involved need to be first and foremost trained in how to learn from quite complex things that go wrong in such events, using an evident based investigative approach. One that preferably avoids assigning blame and lead us to the evident truths of all such (physical (parts) people and paperwork) matters involved. 

Check out 'Latent cause analysis' developed by 'Failsafe network'  that for me is the method of choice that I was seeking for decades and discovered late in my career. This method ticks all the boxes, yet sadly, 35years too late for me.

Rest assured this one of the essential missing skills in my view evidently needed 'when thing start and do go evidently wrong'  during our drilling careers that was never afforded to us. 

Having these wider skill sets in a much more complex world of drilling today is surely more warranted today than ever before, to be able to pick up on the early warning signs of all such matters before more consequential (non-injury related) operational safety incidents/accidents result. Failure Prevention always preferred to drilling time consuming and costly cures.

AI, machine learning, big data and digitization may assist in this?, i.e. assist people today to reduce operational safety failures that still too commonly and evidently result.  

Consultant ( sort of retired but keeping in touch )
SPREAD Associates
Total Posts: 42
Join Date: 27/03/11
Adem hi, 
if you can give an update on your problem it will helpful for similar future enquiries.
Have you fixed your issue, if so what did you do and was any reply more helpful than others.
Regards Howard
SPREAD Associates
Total Posts: 164
Join Date: 05/03/08
Hi Adem,

If you were not getting such problems before, then the question is; what has changed since then?

Ranging from a new (possibly bad) batch of DC's to the BHA design to the well type, something has changed.

As noted by other posters, using shock subs and RR's are quick fixes, but tend to disguise, not cure the problem.

It's clear you have a vibration problem, but you need to identify what type of vibration is occurring. In that respect, running a vibration data acquisition tool in your BHA is vital.

I don't mean using the data from an MWD tool, as it's sample rate is too low.

Run a dedicated vibration sub (there are several on the market) which takes data samples at 10 - 20 times per second that can be downloaded and analysed at surface.

This will tell you what type of vibration is occurring and possibly also what conditions are increasing / decreasing it.

Once you know this, is makes the task of designing a fit-for-purpose BHA and running parameters to avoid vibration much simpler.

All the best!

Well Construction Lead
Total Posts: 26
Join Date: 27/02/16

You have received already relevant advices:

  • Use of BHA components (DCs, STABs, etc) featuring connections’ SRG (Stress Relief Groove) & BBB (Bore Back Box) per relevant API RP
  • Stabilizer high grade hard facing (HF5000 or 6000 to be considered)
  • Monitoring cycling fatigue (setting bits, DCs, STAB, JARs, Krev limits is an easy way to do it for your drilling conditions)

Then stabilizer design and Bit-BHA design (stabilizers space out) are other IMPORTANT http: levers to consider.

Deep geothermal wells, through hard basement rock (granite, …) is generally very demanding on Bit BHA components. Rock is hard, ROP is slow, drilling vibrations (whirl) mitigation is challenging. Cycling fatigue do occur in these conditions, as well as abrasive wear on drilling component that may lead to extensive reaming needs prior resuming drilling.

Attached some hints from Fred Dupriest towards better BHA design, mitigating Bit-BHA vibrations (BHA proper stabilization is key).

I can also recommend ExxonMobil SPE-189649 paper on stabilizer selection guidelines.

D&C Project Coordinator / Decommissioning
SPREAD Associates
Total Posts: 37
Join Date: 25/01/16
The issue is definitely harmonics which is an amplified vibration.  Interesting that the issue of harmonics has been modelled and understood since July 1986 and to this day engineers are not designing around simulation for understanding.  ALARP is like the Bladder Effect of a migrating gas bubble.  The process integrity gets limited..   
Consultant [retired Shell staff]
SPREAD Associates
Total Posts: 280
Join Date: 02/09/05
Suspect vibration, and act on its mitigations
lack of proper DC relief grooves,
External relief grooves the best vidé example

6 5/8" FH mod [7” swallow] > 6 5/8 REG [5” swallow] [NC-61 – 5 ½”; 6 5/8” FH – 5” swallow]. 

External relief grooves > 5,500,000 cycles; API IF mod 393,000 cy; API IF 240,000 cycles.

Consultant ( sort of retired but keeping in touch )
SPREAD Associates
Total Posts: 42
Join Date: 27/03/11
Can you describe the shoulder damage, is it circumferential? You mention connection cleaning, is it dry before applying the compound ?
Hard rock geothermal drilling is always v hard on all BHA components. We had one occasion where the operator changed out the BHA every trip so they could clean, inspect, reface etc every connection before next reuse.
Assuming the DC thread, OD, ID and material have been correctly used to determine MU torque and as you say the gauges are correct then all should be well. Are the tongs set at correct angle and level. Plus have you considered using a MU torque of +10% of recommended ?
Regards Howard.
Consultant Driling Engineer / ERD Advisor
Stanfield-Hayes Consulting
Total Posts: 45
Join Date: 25/03/11
Based on this limited information it could very well be a consequence of the high vibration/shocks, as it sounds like you may have a whirl issue. The specific type may be identified from the wear patterns on the stabilisers (one sided vs. even) though it does sound quite severe.

It would also be useful to understand more about the drill bit being run and there condition, ROP's etc.

If this analysis is correct then as far as solutions go, the first part is to look at the assembly, the bit and the trajectory. While there are 'band aid' solutions like roller reamers, shock subs, anti-vibration tools, etc, the best first action is to improve the BHA design and bit selection to reduce the vibrations. If you are still getting wear you may also want to look at better hard facing on the stabilisers too.

It's also worth considering the holistic approach and look at the whole well design, fluids programme, etc as there may be additional solutions that can be made.

Then when drilling change the parameters, WOB & RPM to find a sweet spot. But if this is whirl then you will need to pick up, switch off the rotary and let the string stop vibrating before returning to bottom with different parameters.

Finally if all else fails select stronger equipment

I've attached an old presentation (2008-2010 vintage) that may be of some use if this is indeed vibration related
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