Extremely Abrasive formation & Losses
28 July 2016
Need your suggestions on drilling extremely hard & abrasive sands, we have used several PDC bits [ 6,7 & 8 bladed with 13,16 mm cutter size] that have come as cored out , Tri-cone comes out with dull grades of 5-6 & gauge damaged badly, [ IADC 437,517,627] have been used, with no success, Max ROP is 0.6-1 m/hr.
Now Impreg is out of consideration, since we are keeping LCM in active system to tackle losses, so motor or turbine cannot be used along with the Impreg.
What is your experience with this? And any suggestion to drill this interval?
We are drilling this in 17" hole btw.
I know it's very late to comment about your topic but since you guys may still have some prospects to drill in the same field its worth mentioning.
Basically to drill hard and abrasive formations, the cutters on the bit must handle thermal and impact challenges. The cutters used for this application must have these two parameters. To be able to increase ROP, running low speed motors would definitely help. There is a specific drill bit company that has their patented Hybrid design which utilizes conical PDC inserts which provides maximum protection to the PDC cutters while pre fracs the hard formation.Those conical inserts have very thick diamond layer and can handle impact loads and thermal. If you need more information, please contact me and I'll provide you with performance report and technical details.
We drilled many Basement wells in Vietnam. Basement or granite are not forgiving as well, you keep the bit too long in the hole, it will come out without cones, or 8-8-1/2 (old bit grading) condition.
We used to drill with Rotary assembly and making 1-2 m/hr.
With the introduction of Motors, we managed to increase the ROP to 5-10 m/hr.
Bits were improved and best is insert bits with full gauge protection.
So far, Hughes and Smith provided the best choice of bits in terms of performance.
Range of bits from API 5-3-7 to 8-3-7. You will have to play it by the ears.
I suggest you consider use of a low speed mud motor/MWD etc with suitable tri-cone. You can pump LCM thru this BHA using correct procedures.
MWD is useful for monitoring downhole shocks and vibration which will help in analysing the problem.
You could also add a multi function PBL type circulating sub to pump additional LCM when required.
We successfully used this approach on a number of wells in SNS where there are some hard abrasive sandstones, and well control issues.
I have not the chance to answer before, and I have to say that I have been in a very similar situation drilling in the Andean Foothills in Colombia.
With the intention of giving you an example of what you could do in "real time", with a partnership with a services provider, I am sending attached a copy of a paper we published some time ago.
About the strategy you had this time of pulling out the a trigone bit every 20-25 m , it is OK as you keep on progress while keep all the three-cones together in every bit you use. There could be more alternatives doing some planning for another job.
I have some questions for you:
- How did you end in this job?
- Is there any similar job planned in the future?
- How open would you be to get another vision from peers via Skype?
Thanks and regards
Thank you all for the response, please find below the answers to your queries
- The footage is around 500m
- Used a non standard bit design due to casing size limitation [ Casing ID was less than 17.5"]
- We do not have RSS in country for this size
- Used a PBL sub for losses, but we need LCM in active system to prevent losses and strengthen the wellbore
- Stinger not available in current size, need to manufacture it and that takes a long time
- Changed the BHA as well, pendulum, slick and packed but nothing has worked so far.
In the current scenario, we are drilling with inserts and POOH after every 20-25 m because of bit wear
I know you had already numerous responses, but here below are my thoughts, which can be perceived by some as general, but it's always good to have the basics in mind.
Hard and abrasive sands are very difficult to
drill with PDC bits, as wear comes from abrasion and impact. The best way to drill
through this type of formation is to optimize PDC bit itself by playing with cutter
size, orientations and set up but also bit profile. We have more than 20 years
of research in PDC bit behaviour and we have developed a complete PDC design
software including bit performance, wear and directional behaviour, bit
stability (including coupling with BHA) to compare several designs, and give finally some "non-biased" recommendations.
Contact us for more details
If your Company allows, it would be helpful to post the bit record and some BHA details to help understand the situation.
It seems strange that the PDC's cored out, but the Inserts suffered gauge damage.
Were the teeth on the PDC & Inserts broken or worn? If broken, this could point towards vibration or BHA configuration rather than formation as being the main problem.
Having just drilled a long section of 30,000+ ksi formation, (albeit in 8 1/2" size), we found that bedding in the bit correctly was absolutely crucial. This was particularly the case for a PDC following an insert bit, or a previous PDC that had come out cored. In addition, a locked BHA was of great help - we would have also used a NB Sealed Bearing Roller Reamer if we could have got one.
Presumably you are not running MWD/LWD due to the losses? They can provide some information on vibration. Alternatively, nearly all mud logging companies can provide string vibration information as a relatively cheap add-on. Very useful in vertical wells.
Otherwise, as previous comments have suggested, do a cost-per-foot/m analysis to find out which is best, reconsider a PDM as most can take substantial quantities of LCM (except Nutplug) and if available, also consider air/foam drilling as an option.
One option could be air / foam hammer drilling. If air drilling service is available in the area, and the footage to be drilled is considerable, I believe, it is worth to check the feasibility of using hammer bits.
Did you check out a stinger bit with conical shaped polycrystalline diamond elements ? See IADC/SPE 17875-MS
I suggest you re consider using a mud motor. It can handle the loss material,( provided the loss material is well mixed and not pumped in slugs) and if necessary use a PBL sub.
We regularly drilled very hard very abrasive sections successfully, 12.25 hole, with a mud motor using a sealed bearing rock bit, it was a successful operation. We did not do any directional work in this section( designed to be the tangent section), but the motor helped a lot with ROP and shock mitigation.
The BHA was completely replaced after this section due to the significant stabiliser wear and shock issues.
If necessary you could use an adjustable stabiliser to help control the BHA in a tangent section.
can you change your casing scheme ? If you can drill 16'' instead of 17 1/2'' it will be a big difference for the PDC cutters.
Impact is velocity muliplied by mass - so the bigger the diameter of the bit the higher velocity of outer cutters. You write the PDC bits were graded cored out - but I would have expected dull grading with outer cutters broken. I have used 16'' PDC bits drilling cretaceous successfully in Germany. Do you need directional control ? Then do not use a motor - too much rpm for the bit - use an RSS system instead, run system with maximum 40 or 50rpm from surface to keep impact on PDC cutter on a minimum.
Why don't you use a PBL sub or better MI Swaco MOCS and act on losses when you get it ? As well you could run different particle sizes of CaCO3 to bridge fractures and prevent losses - that should be fine for the TFA of the impegnated bit or the motor.
We drill through loss zones and unstable formations here in Khazakstan with 8 1/2'' impregnated bit and turbine - so we pump LCM (Soluflake fine and medium) to cure losses and use in advance CaCO3 bridging material (5, 25, 50 microns 1:1:1 - checked with plug tester). What kind of losses do you have ? I assume severe losses. For LCM a wide range of materials can be used - so find a mixture which is pumpable through motor or turbine and you could run the impregnated bit.
I got a picture of me and a 16'' impregnated bit - but I never saw a 17 1/2'' impregnated bit - that must be really expensive and will burn down the matrix with that high outer speed.
Could you reduce mud weight to prevent the losses - reduce flowrate to reduce ECD, maybe even drill underbalance or because you are not to deep drill with air ?
I recommend you run Cost-per-Foot analyses on each of the runs and make the bit selection based on proven results.
In reference to the gage problem, look at adding a "sealed" bearing "near-bit" roller reamer to cure that (note the emphasis on the words "sealed" and "near-bit").
Hope that helps.
Some questions for you...
What is the footage of this abrasive interval?
Why 17" - it's a non standard size and that will reduce your bit choice.
What sort of mud system are you using?