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PDC Under-reamers - Bit-BHA-UR systems approach
11 March 2014
With more exotic contingency strings being planned, PDC under-reaming is becoming much more common and successfull so I am informed.

We are therefore looking at planning, engineering and working to be able to under ream (as a contingency) in what will be a "Cretacous formation" potentially 700-800m sequence on a offshore well, from a floating rig, at a tangent angle of 38deg in hole size potentially from 8½ to 13½ using SOBM.

Lessons learned?, recent experiences?, knowledge gained items to discuss with manufacturers etc, appreciated.
- optimal bit under reaming configuraiton
- stabilisation on lead bit and behind undereamer
- weight and length below under-reamer?
- under -reamer preferences (size of cutters?)
- flow balancing, nozzling preference
- drilling measurement tools below under reamer (benefits seen?)
- operating hazards, risks to watch out for an how to best mitigate these?
6 answer(s)
Drilling Specialist/Well Engineer/Training Consultant
Total Posts: 339
Join Date: 10/01/05

Looking at an old bit selection chart.

Cretaceous is more akin to Northern North Sea but with no chalk that often sits in lower Palaeocene or into Maastrichtian.

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

Hello Mark, thanks for the comments.

Cretaceous has been uplifted so coming in at about 600m below seabed at about 1900-2000m brt Not sure exactly what this does to drillability. A tad easier perhaps as less overburden compaction forces acting on rocks I would think!  

No chalk is prognosed or seen in offset. No under-reaming conducted on offsets but we have some regional experience. I am hopeful of some good supporting data from vendors that I expect in next few weeks.

We therefore expect large upper cretacous sandstone packages with claystone interbeds and occasional thin hard stringers perhaps that would need to be carefully managed. How well cemented sandstones are?, could be a genuine risk! 

So perhaps more drillable than we would expect in Central North Sea once we hit chalk and then the harder sandstones below this.

Deeper in well in 8 1/2 to 9 1/2in options, then perhaps getting into lower Cretaceous equivalent of Cromer knoll group in CNS!

In worst case scenarios, e.g. we hit shallow water flow and have to set an extra surface string. At some point we would have to under-ream from 12 1/4in to perhaps 13 1/2 to accommodate 10 3/4in casing planned.

Then 8 1/2in hole would be under-reamed to optimal size with few contingent options around this required.

In shallower sections it is likely we would try (if data supports this) to drill and under-ream in one run.

Depending on geological results and uncertainties we may also drill and then under ream later.

So I am planning to have bit/bha, designs and engineering scrutinised for plans a,b and c as usual!

Anything else springing to mind, all comments welcomed in review and assessment currently on-going.



Marathon Oil
Total Posts: 7
Join Date: 12/12/05
Hi Peter, that's a lot of questions to consider & I can't answer them all. In order to help, I would like to know:
1. Is it corect that you plan on reaming while drilling?
2. What "Cretaceous formation" are you drilling, specifically the lithology type (chalk, marl, dolomite etc.) & is it homogeneous, or does it have distinct beds or boundaries? This will have a huge impact (possibly literally) on the cutters.
3.Have any of the under-reamer providers sucessfully drilled a similar lithological interval of this length with similar enlargement?
Also is it correct to interpret your query that you will be drilling an 8"" hole & enlarging to 13""? If so, the under-reamer will be displacing more rock than the bit (simple check using cross-sectional area, proably with fewer blades. The linear speed & work rate of the cutters will be high too. This all introduces risk.
My firm belief is to drill as large a hole as possible & enlarge it as little as possible -full bore is preferable. It sounds interesting though; you know where I am!
Drilling Engineer
Addax Petroleum
Total Posts: 15
Join Date: 16/03/14
Hi John,

Do you do the modelling with Schlumberger? What tools/companies are available to perform this kind of modelling? Thank you very much!


Larry Zhao
Drilling tech advisor
Franks International
Total Posts: 12
Join Date: 13/03/14


We have many runs now utilising the new anti-vibration tool (HI Tool) from Franks Drilling, this tool allows you to decouple the cutting structure of the under-reamer from that of the bit which in most cases can be 30-50m away at the bottom of an RSS being run in the pilot section of the hole.

I have a few suggestions in order to optimise you UR BHA design:-

  1. Flow split at the UR should be in the ratio of volume of rock being removed by UR compared to the bit, but this split should never exceed 30% or you risk starving the bit and BHA tools below the UR.
  2. Have the bit selection such that the weight distribution should be maintained at around 75-80% at the bit this means that the bit is what determines the ROP and also more importantly is that the pilot BHA remains in compression which is what helps eliminate most of the vibes.
  3. If possible try to have the UR well centralised in the pilot hole by use of a near gauge stab below (or roller reamer) especially in higher angled holes, if you have time then have the leading edges of the stabs pacified (radius); this helps reduce slip-stick at the contact points within the pilot BHA.
  4. Think of running a full drift stab around 1DC above the UR; this reduces the bending moment going into the top of the under-reamer, limiting deflection of DC's etc. above the UR.
  5. Some DD companies advocate running HWDP below the UR to try and decouple the UR from the pilot BHA this adds to rathole length, the simple solution would be to add the HI tool from Franks Drilling which has the same effect of decoupling, also centralises the UR and does not add any more to the rathole.
  6. You might think of running a dormant NBR at the bit with 'up-reaming cutters' so that once you've reached TD then you can activate the NBR to ream up the rathole all with one BHA so you are left with enlarged hole all the way to TD, these tools can be pinned and activation closely calculated by/to bit pressure drop. While dormant the NBR just seems like a NB stab.
  7. If possible have the period between contact points in the pilot BHA varied; this will also reduce the risk of hole spiral as you push 75-80% of the weight to the bit.
Hope some of the points have been of help.

Cheers, Dave
Drilling Supt- Benin
Total Posts: 3
Join Date: 15/08/11
I have been involved with some under-reaming in deepwater from a drillship.  There are lots of issues but the two main ones are
1. Vibration and subsequent string or cutter damage
2. Length of rathole remaining and whether the casing design can tolerate a large rathole or it needs to be opened out.

We have been using Schlumberger and string design modelling is absolutely critical in order to reduce vibrations down to a survivable level, this requires a lot of modelling by the provider.  We are about to introduce the Tomax Anti Stick Slip Tool which attempts to balance the weight on cutters of bit vs reamer which is otherwise an uncontrolled variable when the bit and reamers are in effect cutting in different lithologies. More on the effectiveness of this tool shortly but we believe the manner in which the Tomax tool 'shortens' or extends the BHA to reduce or deepen depth of PDC cutter engagement into formation will work for us.
You will find that there are different sorts of reamer available. While 'drop ball' designs are commonplace to trigger the opening of the reamer blades, emerging 'on command' designs make for either a 'redundant' reamer to be placed into the BHA in case the primary one gets worn out (a common mode of failure) or placed in the base of the BHA as a 'rathole killer' so that if a long rathole (40 to 60m) is intolerable for shoe placement then a telementary designed on command reamer can be activated to open up the rathole leaving around 10m thus avoiding the need for an additional trip.  Need to watch LWD tooling compatibility with this design though.
Modelling is absolutely key and then there's the hydraulics for nozzling etc but that's another story
John Penhale
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