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Jetting with PDC bit
17 May 2018
We are planning to jet 36" conductor and drill 17.1/2" hole immediately below. Riserless interval 1300m through Tertiary deepwater shales, nudging into Cretaceous age formation at section TD.  Offsets used milled tooth but riserless interval was shorter. Some evidence of firming up but not entirely clear.

Any experience using PDC for jetted interval and riderless section in similar deepwater setting? Reactive torque possibly an issue? 

Note from moderator (21st May): Please can we keep focus on the point of the queston, which was about jetting conductor using a PDC bit.
3 answer(s)
Managing Director
Damask well engineering ltd
Total Posts: 2
Join Date: 15/08/17
Hi David,

I think i can help you with your question?  I drilled 13 deepwater wells in 1000 - 1500m WD.  I believe my advice will be contrary to some of the advice received thus far.

If you are drilling riserless then the seawater column is factored in to the BHP.  Therefore the statement that you have no mud weight from sea surface to seabed.  The hydrostatic column acting on the Bottom or current bit depth is to LAT you should use this to calculate BHP.

In deep water wells even though cuttings are dispelled at seabed - the pressure gradient is to sealevel.  Therefore a double calculation is required, however ECD will and needs to account seawater depth.

Your pump and circulating pressures and in well control too - should account for clean drilling fluid (this is normally seawater!! with hi-vis sweeps for both conductor hole and the next surface casing hole section, why because returns are to seabed and to stop environmental damage to seabed.

There are also some other concerns I have with your potential plan that I can discuss one to one with you by email.

Please email me at xxxxxxxxxxx I am available to assist you.

Note from moderator: It is preferable  if you can share this all the members

(retired) Well Fluids Team leader
Total Posts: 40
Join Date: 14/06/06

I see Peter has answered the drilling question.

Do you have a wellbore stability model or an expert to talk to ?   If you are going to drill tertiary shales what is their collapse gradient and from what depth is the required MW calculated?   
As you drilling riserless you have no mud weight from sea surface to sea bed . Does your model assume the mud weight required is calculated from rig floor or from sea bed !  
There are a number of train wrecks from failure to get the casing  down in these deep water wells in UK and Norway due to collapsing hole.   You need the planning driller to talk to the WB stability focal point .       
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 361
Join Date: 10/01/05
David great challenge, that is achievable in my view, and likely has been done in various components parts that may need to just be brought together to best fit ones needs.

e.g. In several offshore and notably deepwater environments where normal pressure regimes exist and no hydrocarbons are present. Pushing surface string as deep 'ALARP' into the first indication of undercompaction is a good strategy if a slender well design meets the TD bill.

Many have achieved this is areas where stratigraphy, pressure regimes, well design hazards / risks and uncertainties permit. e.g.

SE Asia 17 1/2" section up to (4,000ft) surface wellbore sections during 1990's via Unocal's SX explorations wells. No conductors used Surface BOP's. I may have some data to see bit used. 

Irish Atlantic 17 1/2" slender well design 1290m (Statoil).
Conductor however drilled and cemented. No bit data provided.

Offshore HPHT wells 26" casings are pushed 1000m +
(smaller 17 1/2" slender wellbores designs offer several benefits if this can be achieved without compromising getting to well's total depth and no of strings then needed.) Roller cone bits typically exclusively used.

Offshore India in >2000 - 3000m water depth surface string (26in drilled 20in casing ) is pushed deeper (>1000m) to get formation strength needed to run the SSBOP and drill the next section. Typically 1-1-5 has never been an issue

However drilling into cretaceous (late, early?) and to assure one bit run?  Getting Bit selection and BHA design I can conclude is central and critical to getting it right first time stratgey. 

Jetting 36" conductors with 17 1/2" bits is well documented.
In regards to jetting, as long as decent nozzles are run in bit, then a PDC is feasible and my understanding this has been done. I have no personal experience of this myself. 

For the remaining section. In terms of bit/BHA systems analysis and preferred choice.  My assessment would be. It depends on exact stratigraphy to be drilled. Exact and precise  nature and constituent of this. How good is your seismic, offsets etc. Be sure to Q and QA Hazards, Risk and uncertainties.

Word of caution: PDC's are not always the most preferred solution? I have personally had these crap out and had to be pulled in tertiary sequences (on well cemented stringers etc). 

If lots of inter-beds and stringers are expected (this is the central issue to address in my view) Where getting the optimal bit / BHA is not that straight forward or as easy as it may seem. Other better optimal alternate to a PDC may be preferred.

Other risk? is running a insert bit on the wrong motor. e.g. High RPM / weight on a stringer again can wipe out an insert bit if best practices are not followed. (I'm sure many have the tee shirts for this also!)

What ever the bit? best-practices always needed to be in place to get a bit/BHA optimally to bottom in one run and assuring pristine wellbore conditions are drilled. The standard Test and measure for this to be to POH from TD to conductor on elevators only!



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