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Spudding offshore riserless with a mud motor ?
17 August 2020
Another bone of contention that I would be interested to gather others ‘Evidence based points of view‘. 

Would be. 

Sharing EVIDENT pros and cons to spudding, ie  drilling and cement an offshore well’s conductor and surface string where subsurface conditions cannot afford jetting a conductor.  

Northern Southern Hemisphere areas, other regions where non-jettable   ) hard ground, sand carbonate dominant etc) subsurface conditions may exist. 

What is optimal ?
MOTOR vs Rotary assembly.?  
Why is this evidently so? 
What does your wells data show/state experience prove ? 
Evident Case study wells examples to share? 

What set up, has repeatedly and more consistently delivered best process safety, optimal,  higher quality, less problematical drilling  solutions. 
Why was this evidently so? 

Looking forward to members sharing evident views on this highly debatable subject, 

Note: Ask the big three service companies? they will always try and sell and tell that a motor solution is best? . 

Despite the Substance and evidence warranted?  to be checked and assessed to back this up. 
8 answer(s)
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 486
Join Date: 10/01/05

Nor convinced on this.
Can you share the incident report that should exist for such a failure that affords an explanation why a motor was the saviour? 

Shock sub or HIT tool generally is the solution to prevented axial/torsional vibration to deal with the physical down hoe evident facts in these scenarios? 

Rotary bha always offering far more options ability to change and play with more parameters to drill optimally through these sections. 

Eg On a rotary with a top drive you can play with WOB RPM and pump rate far better. 

With a motor you are limited. Eg in cobble pebble beds. You need significantly more flowrate to clean the rubble out of the hole. Motor is restrictive. 

To drill faster on harder ground, general rule of thumb if low rpm and more weight . On a motor to reduce bit rpm one has to reduce pump rate? Again counterproductive! 

A further hazard often not taken into account are rotary resonant speeds? where 80-90rpm is often the range  where all vibration hell kicks off In these regions depths if not accounted for. 

Where if this is not identified as a Potential root cause you will have severe failure / inhibiting issues. Here a motor could physically help! 

Where with a rotary bha you need to rotate 20rpm slower or faster to avoid these events at certain deity intervals. Eg We have a North Sea field case study that proves this was the root cause of previous bit hole opener Drilling problems Bit and tool damage on previous wells.  

Eg we have Drilled through  numerous glacial drift,  till, cobble inter beds hazard sequences. 

- Offshore Greenland several wells,
- Norwegian Continental Shelf, numerous times 
- NNS, CNS, West of Shetland predominantly with rotary Bha as the preference, when we got to choose.

In surface hole due to length of section we have on occasion when hazards / risks were presented. Preferably Ran shock subs and the HIT tool with great success. Ie  minimal axial torsional vibration resulting at Bits in high vibration known areas. 
Conducted resonant speed calcs and stated these in the drilling programs. 

Optimal BHA candidate selection therefore needing to take all factors mentioned in these posts into account. 

Where the drilling engineer should really afford a short document to validate an evidence based records as to why bha was determined evaluated and selected. 

Drilling/Completion/Abandonment Superintendent
Drilling Consultant
Total Posts: 7
Join Date: 05/06/20
Peter a couple of advantages are the motor helping bit bounce damaging the TDs. On a CNS well the drive sproket came off in the gear box. 72 hours NPT for J. W. McLeaan on a Kyle well. Secondly the assy from motor upwards is already made for the next section so it is faster. It has nothing to do with inclination orr WOB though at light WOB you get faster ROP without compression worries.
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 486
Join Date: 10/01/05
To support the post.  UK / NCS typical spud 'best in class', July 2005,  Evidence as attached.

1. BHA details.
2. DDR from day 1  Spudded with BHA / Anderdrift at 19.50hrs
3. DDR Day 2 BHA pulled and laid down by 02.00am  
Starting to run conductor from at 02.00am hrs.

4. Mud loggers Drilling log. (increasing WOB throughout.)
ROP 50-100ft/hr (instantaneous in silts/sands?)
5. Bit /hole opener record.

Interested to review any current offshore UK / NCS or other regional wells top hole data in comparison?



Documents uploaded by user:
2005 top hole rotary anderdrift data.pdf
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 486
Join Date: 10/01/05
Thanks Daddy cool. 

For the response. Good to see some are taking a 'keep it simple' approach. 

To drill optimal top and surface hole straight (if this is the requirement), i.e. through typical quaternary and highly drillable tertiary formation sequence in the UK and  NCC). The physical resolution is that one need 'stiffness and rigidity' according to the theorems evolved? 

So the bigger drill collars and well afforded stabilisation and optimal nozzle selection is key and central in these sections to drilling trouble free, optimal and straight sections. e.g. Ever  include an 11" collar?. We saw big improvements.

I have to question in the WOB strategy statemented i.e. limited to 5K?

Where is there any physical evidence for such limitations? 
Where to assure optimal straight hole drilling, knowing where the WOB limits are is also key.

Where is optimal WOB strategy in the drilling program? vs 5k is OK?

The best top hole BHA example I have experienced that we simply adopted as our optimal starting design. (where main problems issues are generally glacial till, boulder, interbeds beds and sand packages etc within UK and NCS top/sruface holes) was evolved in the Heidrun area. Why? Because it ticked all the evident boxes and was well proven. 

Where Conoco through the pain of early failures, evolved a pre-made 40ft spud stiff rigid stabilised, BHA, that included a 11in pony and a 36" spiral stabiliser a tad behind the hole opener. 17 1/2@ bit short 11in pony, 26/36" hole opener, inclinometer, pony DC, 36" spiral stab and a handling pup. First stand of DC's also had a 26" stab to afford further stand off and that was then used in the surface hole BHA   

Optimal Process was that we picked up a 17 1/2in bit, placed it in the bit breaker. Then picked up the complete 40ft BHA in one lift, (using DC elevators) and made this up.  RIH. removed the handling sub and then started running the rest of collars and BHA. Simple. Firs stand of DC's was 2 9 1/2" and one 8' DC. We then only used one set of drill collar elevators within the DC's BHA!

During drilling, we would stage up WOB (taking a inclinometer survey every 30ft) until the 36" stabiliser was buried. Then dependent on parameters observed and formations drilled, etc then linearly increases weight with burial to approx 20K
Only if we drilled into a large sand or had vibration issue son boulder beds etc. In the bigger hole size we would evaluate if we had to slow down change parameters, and pump bigger sweeps (i.e. 100-150bbls) needed to clean the hole.

Where when one understands all the physics downhole conditions and and maths involved.  All should know and be fully familiar and understand where the drilling and hole cleaning limits are in the extremes. 

On POH, we reversed the process and sent the BHA back to town. About 8hrs rig time we estimated were saved to effect a much safer effective and efficient BHA handling process. 

In early days we rarely also ran MWD, WHY? Because an inclinometer only just above the hole opener is what we had evolved to be faster cheaper best option. As we could survey right above where the hole is being drilled. vs a MWD that is tens of ft behind the bit and hole opener and for a 200ft conductor is just another waste of time.

Tried in later years to convince people this was the evident best way to go. To be resigned to be out numbered by consensus despite lack of evidence agreed solution support this as the better or best BHA.  

A further forgotten benefit?  is that if one drills into a shallow water or gas flow scenario (that often arises on the NCS) ? Where having a motor or MWD restricts ones capability to pump at the maximum planned rate to kill the well (should a worst case result). Please be advised that with this BHA you must assure you have a pre-signed contractual agreement with the service companies in black and white that in this scenario, the driller can exceed operating circulating rate of these tools (needed to dynamically kill the well). Otherwise service hands will be telling the driller he cannot pump more than the limits, and unable to dynamically kill flow experienced. And face the consequential weeks of loss of well, abandonment and re-spud that then results. With plenty of these train wrecks on the NCS for all to review!

So when there is no directional drilling to be done and you want to go straight and there may be a shallow flow hazard/risk?. A stiff rigid well stabilised BHA with an inclinometer is what we have learned and experienced as the most fit for purpose design.

That remain as the most optimal experiential choice until better physical, local knowledge and experience, rules reg's standards evidently states to do otherwise?  
Drilling Supervisor, Drilling Engineer, Directional Driller
SPREAD Associates
Total Posts: 1
Join Date: 29/07/20

Can someone provide some example motor-BHA’s you perform spudding with?

As recently as 6 months ago I spudded a well in the NCS with a 26x42 BHA no motor. Everything went perfectly well, I double checked the engineering on the rig and my main concerns in executing were planting the bit & HO straight, and then ensuring smooth, controllable drilling (by limiting WOB to ~5kips) to ensure balanced WOB across bit & HO. We didn’t wait for low tide, we bedded the bit at about 1 degree inclination and skidded over the rig by about 2ft (adjustment will vary depending on depth to sea bed etc - make a rough Pythagoras calculation). As an exploration well, if we’d had to we could have easily respudded but I know that won’t be the case in all circumstances.

To be honest I don’t really know where you would put the motor - above the HO?? If rathole length is not a concern then I guess I can see positives to the motor being below the HO. It will ensure that the bit drills off faster than the HO, stabilizing the WOB distribution. Hydraulics might be tricky, though nothing is likely to be running at full efficiency in this scenario. The smaller annulus may help transport the cuttings but on the other hand it leaves plenty of scope for packoff…

I think there is some conflation going on with the discussion about steering. How do you steer in a 200ft spud hole? As another poster mentioned, you might not even see the results as they’d remain ahead of the MWD. I guess in some cases you may drill a pilot hole to be opened afterwards. In that case then sure, run a steerable motor if you want. If running an 11” motor in a conductor BHA I would expect a straight housing, or zero bend setting. By the way if you do want to steer, you can actually scribe in easily enough up to, say, 1000ft. You are not looking for precision there, just ensuring you point the spoon in the right quadrant. If AC is a big concern, you need GWD if you want to maintain any pretence of having process safety.

Nonetheless, I dispute the belief that the big 3 OFS companies would always recommend a motor. 5 hours BRT is not going to impact their bottom line, especially as any revenue may need spent on servicing, reline etc. In my experience we look at local offsets for the first guidance. I can imagine perhaps recommending running the motor if it saves BHA time eg. to the 26” BHA after the 42x26, but this is less of a concern now with dual derrick rigs, pre-made-up BHA components etc.

A benefit of the motor is to add weight to the BHA, some drillers like this as it reduces stress on the top drive. I suppose the net effect depends on how far to sea bed and how hard is the formation. Maybe more of a concern on land.

Have you considered CWD as an alternative? This is a very common tophole approach in the Andaman Sea and Gulf of Thailand, although to be fair the formation is extremely soft there.

Operations Manager / HPHT Drilling Superintendent
SPREAD Associates
Total Posts: 6
Join Date: 08/04/18
I am happy chipping in to the conversation Peter.  

The experience I was referring to, and my pet peeve I was referencing, was for situations very recently from a jackup. The hole size was 26” for a 20” conductor. For a number of years and a number of wells and the vertical top hole sections, I couldn’t win. Me, as for you, next well and the motor remains!

I don’t fully follow including a motor for addressing concerns for the BHA hanging plumb for spud. I have difficulty connecting the dots on that one.

Repeating and supporting what you have pointed out, the physical evidence checks in the moonpool, ROV current meter, and observation of BHA at the sea floor, and survey tests conducted addresses sea current concerns near the mudline. Tides and currents ebb and flow. A few hours can make a lot of difference to, if needed, find a quiet current period to spud.

Through the decades as you say, I too have experienced all the problems you mention, from the other side effects from including motors, indeed worn skidded and lost cones on hole openers, difficult BHA handling (9½” motors are cumbersome enough let alone the 11” sizes) and limited drilling parameters options for rpm at bit. With the motors of the size used in the spud assembly, warning signs coming from below the stator are for the most part isolated from surface, warning signs that one would otherwise clearly receive with a non-motor rotary BHA.

Unfortunately arriving at solid decisions from objective discussions and studies weighing likely outcome benefits, or not vs. offset well experiences, measured against optimal value and real objectives desired becomes difficult when the decision making is tainted by skillful sales people and DE’s that want to cover all the bases regardless the logic of doing so and the cost for such.

Quite a few words (reusing a lot of yours) to simply say, on the matter of leaving the motors out of spud BHA’s, I agree with you, follow the keep it simple principle, leave them out unless there is some driving risk measured tangible reason to include them. And from yours as my experience, such driving tangible reasons are indeed rare. 

My pleasure,

Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 486
Join Date: 10/01/05
Appreciate the response Allan.  

Way back in early Northern Atlantic Hemisphere deepwater well's (well drilled and cement conductor cases). The sole reason / rationale given to me by a very competent SDE was that he included the motor because the onshore team had unproven concerns about the BHA sitting straight when we spudded. 

However on spudding we could see in the moonpool and ROV current meter displayed, and observation of BHA , and the survey test conducted that all the physical evidence indicated that there was very little current in the lower portion of the water depth. The BHA was dead plumb straight.
I remember my tour report then highlighting all the reasons why a motor is more of a deterrent in these particular environments/situations to assure and deliver optimal performance for several more practical and evidence based reasons that I raised.

Next well? motor remained!

Thereafter when empowered, we generally made an more evident based case to case approach to assure we had the best drilling assemblies based on all hazards/risk, reasons, rationales to be determined and evaluated.

Through t decades, we have conducted the offset bit/BHA studies (always a good place to start) to gather all the wells necessary evidence of bit choice and Motor vs rotary BHA's in the same region. Again rotary generally always came out on top in terms of several metrics one could apply in such a review /  assessment.

In fact, Quite a few more train wrecks evidently resulted, due to other side affect of Motors not often considered! (e.g. worn skidded and lost cones on hole openers a key hazard/risk impact area to scrutinise).  More BHA MU/BO handling time, less drilling parameters options when it comes to drilling interbedded formations sequences, Limitation on pumping volumes capacity etc. etc. are facts laid to bare.

We should always start with a rotary first and then take an evidence based case towards making EVIDENT based changes needed to assure outcomes benefits optimal value desired. BHA / technology add-ons, must prove and demonstrate  added project/process, risk reduction value! 

Thanks for taking the time out to respond. 

Operations Manager / HPHT Drilling Superintendent
SPREAD Associates
Total Posts: 6
Join Date: 08/04/18
Hi Peter,

Starting with the last point you raise first; indeed all the service companies will sell a motor to younger engineers by posing the scary (to the DE) question, what if? And the motor provider will also insist on a bend setting on the motor. The 'what if' referring to potential deviation build.

How on earth will one be able to orient the bit and motor in unconsolidated subsea top hole, with an 11" motor in 36" (bit size not washed erosion size) hole? As illustration of this, ask the motor provider to start/program a build up section of any build up rate, from vertical, shallower that 200m from mud line and watch the reaction.

The motor puts the deviation sensors at least 10m back from the bit, as well as GR-Res (kills any GR 'at the bit' possibilities) which in my view should be planned as close to the bit as possible on top hole, pilot or otherwise. With the combination of MWD/LWD log information immediately above the bit together with the drilling data, one will identify stringers and potential ledges very quickly to allow reaming these out.

Top drives can turn the pipe and bit as fast as any high torque motor. Spinning the drill string faster stiffens the assembly thus amping up the restoring force of a pendulum assembly.

As a consultant these years I have never been successful to convince the worry induced DE there is no use to run a bent housing motor. 100% of the time the motor has proven to be no advantage except as you say to the motor provider. On a few recent instances orienting was attempted with, predictably, no success whatsoever.

Although not common due to rapid hole erosion in top hole, more common if soil becomes more competent deeper, in rotary mode with higher WOB, the bearing housing stabilizer on the motor can introduce a pry/build force at the bit negating any pendulum or restoring action that one can achieve by keeping the pendulum drilling assembly o.d. clean for 10m to 20m above the bit.

Kind regards, my views, my experience,
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