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Shock & Vib - BHA related
08 March 2016


Trying to optimize intermediate BHA in effort to decrease shock / vibe & would appreciate your thoughts & experience (good / bad)  with below...

1)  Currently running 8" NMDC, then XO to 6-1/2” DC´s.  Would additional 8” DC´s help to minimize shock/vibe by maximizing inertia? Any downsides?...are HW a better alternative?

2) Effectiveness of shock sub or other shock./vibe dampening tools

3)  Effect of bit guage length

4)  In production section, the effect of slick vs flex NMDC while choosing DCs

5)  IBS vs roller reamer effectiveness


6 answer(s)
Drilling supervisor
Sonatrach Petroleum Corporation
Total Posts: 4
Join Date: 11/02/16

We ”˜ve faced serious vibration problems in Hassi Messaoud field in the intermediate section (16” hole ) which prevent us from achieving the total length of the section (+/-1800m) in one run. First of all we have to bear in mind that drilling parameter are as important as the type of BHA to mitigate drillstring vibration and bit damage. This is because the natural frequency of a drill string at particular RPMs can be the source of significant vibrations which can be axial, lateral or torsional.

One of the approaches we´ve implemented to alleviate this problem is the use of Super Packed Hole BHA by the introduction of a 3rd stabilizer. The idea behind running a third stabilizer is to increase the BHA inertia momentum, which would rigidify the BHA and make the torsion more difficult. We use 9" DC along with 8” DC and 5" HWDP. Moreover, adequate drill bits should be chosen with good Lateral stability Index LSI to reduce bit whirl. A type of bits that have proved their efficiency in term of cost and resistance to damage.

As for shock subs, use them mainly in the 26” section as the drill string weight is not enough to overcome axial vibrations.

Concerning roller reamer, they are mainly used in sections where backreaming is needed. 

Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 352
Join Date: 10/01/05

Lets assume worst case (wellbore less than 30deg) for shock and vibration.

1)  Currently running 8" NMDC, then XO to 6-1/2” DC´s.  Would additional 8” DC´s help to minimize shock/vibe by maximizing inertia? Any downsides?...are HW a better alternative?

I would be running 9 1/2" and 8 1/2" combination.

In harder formations and at lower ROP run more 9 1/2" vs less.

2) Effectiveness of shock sub or other shock./vibe dampening tools

Yes we have seen distinct benefits of shock subs and other tools in specific lithology's where shock and vibration have been a problem. (assuming wellbore remain in gauge and is not washed out or has large enlargements due to vugular formations etc)

3)  Effect of bit guage length

Studies and field result Cleary show the physical evidence that the longer the gauge the less the shock and vibration that will result.

4)  In production section, the effect of slick vs flex NMDC while choosing DCs

I have no apparent answer as I am not sure what you are seeking here in the context of vibration etc?

5)  IBS vs roller reamer effectiveness

Avoid bladed or in li-ne stabilisers.

Spiralled IBS preferred.

Number off and placement of stabilisers (and understanding typical weights and rotation ranges to be applied, formation sequence to be drilled) are some of the critical aspects to recognising, analysing and  therefore designing to reducing shocks and vibrations.

In this one generally needs a 3rd party software to be run to assess the criticality, risks etc of these.

Roller reamers: As far back as the 80's and several times since in specific regions and application in difficult lithology's. We have run roller reamers to good effect to enhanced wellbore quality that in turn reduces likeliness of shocks and vibrations. Todays' modern RR's design that are also much more reliable than those in  the past.

Drilling tech advisor
Franks International
Total Posts: 13
Join Date: 13/03/14
There are some very good shock tools on the market which can be placed in the BHA either at the top or at the bit depending on where you think the vibes are being generated. By using a shock tool it allows you to maintain good parameters which will give good ROP and footage without compromising any of your BHA equipment. If you need some good case studies then please drop me a note of your email address and I can send you some info.
Better still if you are in Aberdeen then I can nip round to visit with you.
Cheers, Dave Rodman (email address provided but removed by moderator)

Note from moderator: It is against the ethos of this FREE site to permit the use of personal emails to directly connect people: so it has been removed.  This is the fourth time in a short space of time that we have had to do this. We will continue to do so, and persistent offenders will be removed from the site.

Documents uploaded by user:
HI tool presentation Jan 2016.pdf
Drilling Supt
Nostrum Oil & Gas
Total Posts: 45
Join Date: 14/11/10
Assume you run a 12 1/4in bit because you use 8'' NMDC - so I would definitive use 8'' DCs instead of 6 1/2'' DCs as long as your well profile is with DLS less than 3.5 deg/30m  and inclination less than 45 deg. With higher inclination and higher DLS use HWDPs instead. Where ist the neutral point for depth in and depth out of your BHA ? Using a 6 1/2'' Jar with your DCs will have not enough impact and impulse - so do not use the 6 1/2'' DCs - Use 8'' DCs with 8'' Jar. 
In case you will drill through depleted area with differential sticking expected do not use DCs - use HWDPs and maybe even the jar with standoff.
To minimize vibrations the heavy BHA will be the better choice, but maybe too stiff for the directional profile. I had great success using the Tomax tool to drill with PDC from shoe to shoe through cretaceous. When you talk about shocksub your offset wells had problems with axial vibrations ?  Shocksub should be Positionen as close as possible to the bit - but directional sensors should be as close as possible as well for directional drilling. 
Roller Reamer are usually not necessary when you drill with vertical drilling system or RSS. In case you get to the limits of TQ and drag they help to,improve borehole quality and reduce TQ. 
Long gauge bit helps to prevent reaming run or excessive reaming before running casing. 
You could use as well cheaper short gauge bit plus turboback to reduce time for reaming. 
In general run an MWD with realtime vibration data to act on downhole vibrations and beeing able to reduce vibrations by changing drilling parameters. In case you would run the 6-1/2'' DCs in a 12 1/4'' BHA I expect vibrational and BHA buckling problems. Too much lateral movements possible on that DCs in 12 1/4'' hole and lower stiffness of the 6 1/2'' DCs. 

Peter-Joern Palten

Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 352
Join Date: 10/01/05
Agree with Stephen, where no one can prescribe without being able to diagnose the appropriate data. Only then can someone properly trained in problem investigation can review to properly label the physics and evident factors behind and contributing to your problems?

Sadly few drillers have been trained to learn from why thing so wrong so the merry-go-round we are on just spins faster with little ever getting truly resolved.

note: All the warning signs will be there, one just needs to looks deep enough. Once causes (note: there is likely several contributing factors) are determined, then a variety of solutions I'm sure can be offered.

It is however important to remember that vibration does not simply just happen. It is cause, where causes can be determined.

Most common source is driven via poor wellbore quality that results from contributing geology, bits/bha/systems design factors, questionable practices employed all that then result in further wellbore deterioration and increased vibration problems/issues.

Fred Dupriest article 'real causes of bore hole misbehaviours' attached is a good place to start your review of common and current drilling industry failings.



Drilling Consultant
Total Posts: 6
Join Date: 26/02/16
This is a good question, however, to give any advice at all, it would be necessary to have more information on the well. i.e. all these things will have different results in a vertical well, a high angle well or a horizontal section. The combinations of each of your ideas, coupled with combinations of drilling parameters will also have positive/negative effects on your BHA.
If you have any vibration data from other offset wells then analysis of this with regard to parameters and BHA design would be useful and a look at the frequency of the vibration (if that data was properly recorded by a downhole tool).
Many service companies have decent critical speed modelling tools which could aid you in BHA design to minimise lateral vibration or whirl.
Generally speaking, stick slip can't be avoided by avoiding specific speeds but can be minimised by increasing your effective torque available to turn the string (by increasing lubricity, decreasing tortuosity of design, etc as well as employing soft-torque, etc).
Shock subs have been shown to be quite effective in many applications, although they can be detrimental in some.
However, as I say, a lot depends on specific application and specific part of the well. What Vibration Mechanism is it you are specifically trying to avoid ? ... bounce, whirl of BHA, whirl of bit, stick-slip, "simple" sporadic lateral shocks, or more complex parametric resonance, chatter or others ? If you've had a service company monitoring vibrations they should (hopefully) be able to explain their data in terms of mechanisms and modes of vibration as opposed to just "good or bad" or "shocks".

If you could give some more detail on the application then perhaps some of us will have good/bad experience in similar situations and can help.
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