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Drilling Through a Fault
19 November 2019

We will be drilling a horizontal well and the landing section passes through a fault. Due to the experience on a previous campaign in the field, we plan to drill the 12 ¼” landing section in 2 runs. 

The first run to terminate 150ft above the expected fault will be a RSS (point-the-bit) with PDC bit. This will be changed to a dumb iron packed assembly with a PBL sub included to allow the flexibility of pumping different kinds of LCM pills to manage losses.

We will then drill circa 300 ft (3 stands) blind. The section planned for blind drilling is a tangent with inclination of 78.5 deg, azimuth 101 deg and DLS 2.5. The dumb iron assembly will be POOH to revert back to the RSS and drilling continued to the 12 ¼” landing depth /section TD.

 The fault is 470ft from the heel of the well and the risk / potential for the packed BHA to drop or build inclination and change azimuth in the 270ft tangent is high. If this occurs, it will cause significantly high DLS to catch-up original trajectory and could adversely impact hole usability (casing running, completion, e.t.c.).

 Questions::

1] Does anyone have experience(s) drilling through fault they can share with me, what kind of drilling parameters did you employ if you ran a dumb iron BHA?

2] Any advice on the best way to manage BHA / Formation tendencies / bit walk with the dumb iron assembly with Mill Tooth Bit since the first BHA is RSS with PDC bit to minimize DLS

3] Any rules of thumb for modelling or predicting the dumb iron BHA tendency?

4]The formation is deltaic continuous depositional, and permeability is high. We are drilling with SOBM and have tried every known LCM in the past including cement with minimal success. Does anyone know of any other novel LCM / Total  Loss Circulation management strategy?

9 answer(s)
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 421
Join Date: 10/01/05
Tayo,

Some good ideas being thrown around for you to consider.

What I think we need is more evident clarification of the following, notably loss specifics. e.g.

- dynamic losses experienced, that starts on drilling into fault?
- static losses?
- subnormal pressure at fault zone only? (resolving this zone alone via a potential solution, likely negates the need for a MPD system here) 
- were you getting returns or not when drilling through fault?
- what specific LCM treatments, volumes, mix etc have been used?  
- e.g. how much base oil etc is typically needed to fill well to establish loss zone pressure. (As stated proactive methods such as wellbore strengthening using the right materials added to mud could potentially work.

On what has been provided so far it would lend more perhaps to a geo-mechanical problem in my view to resolve vs a managed pressure one?

Do you know or have any sense of Hmin azimuthal direction of the region?

If not can you obtain or do you have a regional multi fingered caliper log or perhaps you should be considering running one (to verify are not drilling in a preferred azimuthal direction!)

I would be focusing on all the physical (wells component parts), people and paper evidence you have or have not, to review, analyse and digest further to lead you to the essential facts and figure needed to identify proactive (prevent vs cure) measures needed to deliver a 'do it right' 'get it right first time' solution that should be feasible vs making multiple trips.  

Wishing you success.


cmcandrew
SPREAD Associates
Total Posts: 31
Join Date: 16/08/10
There really is not enough information given to justify writing much, as leads to too many assumptions, but is this a fault communicating to a low-pressure or depleted zone, or are you crossing the fault into a low-pressure block ?
If this is a new drilling campaign, it seems you should rethink the whole design from scratch.   
Stay away from the fault, or hit it/cross it  higher up in near-vertical hole- reverse direction of horizontal.   You may have a very  ugly looking directional design on paper but it will end up much cheaper:    blind drilling pumping  SOBM  away,  a few feet above your reservoir, hope oil not gas but that is still a red flag- and I assume offshore.
Boumezrag
Drilling supervisor
Sonatrach Petroleum Corporation
Total Posts: 8
Join Date: 11/02/16
Hello,

First of all, what have worked for us may not work for you.

It's better to look for offset wells to avoid doing the same mistakes.
  1. As far as severe to total losses are concerned, it will be a good drilling practice to reduce drilling parameters especially the flow rate without jeopardising hole cleaning 
  2. To overcome formation tendencies, it's better to use RSS with a multi circulating sub to pump LCMs if necessary. 
  3. The BHA will follow the formation tendency, even with packed hole BHA
  4. With severe to total losses, cement plugs were the only solution with some additives such as Format plug from Halliburton.
I hope it helps you, Tayo

Best regards

Mohamed
jknight
Director
Drilltools Ltd
Total Posts: 3
Join Date: 13/01/19
Hi Tayo

On the losses situation this looks like a possible candidate for Pressurised Mud Cap Drilling.

This is a common way to drill through massive loss zones using a choke manifold on the annulus, an underbalanced annular fluid (with some surface pressure) and a sacrificial drilling fluid.

I don't know what your mud weights are or whether you are onshore or offshore for availability of sacrificial fluids but any MPD service provider would be able to supply advice and equipment to allow you to do it.

Shell have employed the technique with great success in Malaysia and the North Sea and it is used offshore West Africa as a contingency for Karst formations or in high H2S wells elsewhere. With the increase of use of MPD the technique is becoming far more common.

_______

Note from moderator: This who are interested in MPD etc, please note that rp-squared (who bring you this free SPREAD site) have an HPHT-MPD service.  

We can offer the full range, from screening studies and planning, HAZOPs (we are a recognised 'independent' facilitator, used by companies wanting to demonstrate independence to the regulators), DWOPs, DWOS (Drill Well on Simulator), drafting JOM (Joint Ops Manuals) and procedures, training, wellsite support etc.

Clients in: Indonesia, Myanmar, Malaysia, Australasia, UK, Mexico, West Africa, Netherlands, Cyprus, Egypt, Ireland, Brunei, UAE, Romania, Guyana
Regis STUDER
Well Construction Lead
DrillScan
Total Posts: 21
Join Date: 27/02/16
Hi Tayo,

Your question 1/ 

Yes experience drilling through faults in deep geothermal application (granite formations) with dumb iron BHA owing to bore-hole instability through faults. BHA included a Rock Bit + NBStab 1/8" under-gauge + DC + S.Stab Reamer 1/8" UG (up & down reaming capability) + DC's. WOB of about 2 to 3 mtf per inch of bit diameter - 80/100 rpm indicative but safe rpm range to be derived from a BHA modal analysis. Avoid indeed critical RPM (resonant BHA operating parameters) which may induce borehole instability through unstable faults. Fault crossing can be identified through MSE real time analysis (MSE / bit ratio patterns). If unstable fault is expected, drill by steps of 3-5m then pick-up backreaming to previous interval 60rpm (more if required) until clear, hence the need for a Reamer S.Stab, clean hole with high flow rate and pills if required, once clear resume drilling by 3-5m steps and repeat. The goal is to mitigate borehole packing off consequences. If faulted area is known to be stable, no need to proceed as outlined above.

Your question 2 & 3/ 

Drilling through a fault will generally result in a local dogleg (a coupe of degress change in inclination / azimuth), hence the need to ream it and purpose of Reamer S.Stab. Additionally, rock bit steerability is high and will drive BHA directional behaviour towards bit side-force (your previous PDC bit used with Point the Bit RSS, genuine Point the Bit (?) is likely a low steerability bit and if so driving the BHA towards bit tilt rather than bit side-force). 

Bit-BHA modelling therefore required to design a hold BHA, playing with NBStab to Reamer SStab spacing, accounting for bit steerability. Use an appropriate Bit-BHA modelling solution (we can help on this should need be - regis.studer@drillscan.com).

Bit walk with a rotary BHA is not something you can control while drilling. At best through BHA modelling you can design to mitigate the walk trend, again, playing with Stabilizer spacing and gauge as well as bit steerability (rock bit or PDC bit). Slightly undergauge Stabilizer may help lmtigating rock bit right hand walk, unless formation bedding planes are unfavorable.

Let us know your experience upon completion of your well.

Regards

Régis

IainDD
Lead ERD Advisor / Engineer / Instructor
Merlin ERD Limited
Total Posts: 10
Join Date: 04/05/16

What are you trying to achieve with regards to drilling the fault? Do you have an idea of the reactivation pressure and how that relates to your mud weight / ECD? Are you looking to utilise LCM material to increase the apparent rock strength (well bore strengthening)? You're talking about drilling through the fault with a dumb iron assembly, then pulling out of the hole and picking up the RSS again. What's the plan if you don't get losses drilling with the dumb iron assembly and initiate them whilst drilling with the RSS?

 

You can limit the drilling parameters whilst drilling through the fault. No tools in the BHA to power so you can drop the flow rate down to minimum levels for hole cleaning (150ft/min AV around the drill pipe) or even lower. Only drilling a short section - drill it with low flow, pull back above the fault zone and then circulate clean prior to tripping out is definitely an option if monitored correctly. Aim for me should be to limit the impact of ECD on the fault zone, if you don’t want to break it down.

 

As far as BHA design goes, your DD company will have some predictive software to give you an idea of the tendency of a simple 3 stab BHA (primarily 12-1/8" NB Stab, 10ft Pony, U/G String Stab, DC, 12-1/8" String Stab, Pony DC, HWDP.....). The size of the first string will be driven by the modelling - probably 11-3/4" to 11-7/8". But then that is only a mathematical model, and my favourite saying these days is "all models are wrong, some are just less wrong than others..." The "less wrong" is determined by historical data. You probably have no historical data of a pure rotary assembly drilling in this formation at this depth. So, where do you start? Look at the RSS steering data and see how much they are having to fight bit walk tendency whilst drilling the tangent. Is the tool steering more to the left or the right when they are trying to drill ahead? If it is primarily drilling straight – steering GTF within an arc towards the top of the hole then I would lean towards drilling with the same bit. A PDC bit will drill the formation at lower weight bit than a roller cone - the higher a weight you have to use with your dumb iron assembly the more likely you will induce a high build rate. A small walk tendency at high angles may be easier to deal with than a large build rate induced by weight. Do some modelling with regards to target and walk rates and see what you can live with. Aim to be as close to your line as possible when you trip, so you have the most room to play with.

Just some basic thoughts. Don't know who you are using as your DD company, but chase after a grey haired DD in there (a dying breed) and utilise his knowledge of drilling directional wells with a rotary assembly.
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 421
Join Date: 10/01/05
We have experienced high instantaneous doglegs when drilling Horst / graben faulted environments in high angle wells. We observed this because we had tools at the bit. 

Key learning was to feather and reduce weight to minimise acceptable doglegs to result. Problems noted were more commonly when Poh. 

The strategy of stiff and rigid with roller reamers vs stabs may work but needs to be assessed with all other factors to consider. Notable strike dip hmin and hmax of the fault itself and how you intend to hit this,

in the past many years ago I recall drilling through a fault ( no losses were experience) but we could not no matter how we tried navigate the direction intended. So a best planned strategic approach taking into account all key factors needs to be discussed with the multidisciplinary team of people needed to be able to assure you do the right things and get things right first time ALARP. 

Wishing you success with this not as rare a problem as one would expect where I trust others can provide further knowledge and experience gained.
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 421
Join Date: 10/01/05
Unocal deepwater wells in the 90’s when drilling with SOBM  used LCP 2000 for high loss events when nothing else worked. They then proved its worth on multiple wells band occasions where the norm was massive losses, gas kick higher up. Stem losses with LCP 2000, circulate out kick using drillers method ( surface bop was in use). Drill to a good shoe formation and case well with an contingent expandable isolation liner. This resulted more than once per well over a period of 100 wells where 1/3 wells experienced this loss/ gain problem.  

I know this because a colleague was one of the long term supervisors on these wells. He stated in these situations and conditions  LCP 2000 rarely failed to stem massive losses experienced in porous permeable formations.

so if we are not taking about vugular or cavernous formations then this could potentially work for you. 
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 421
Join Date: 10/01/05
What is loss rate expected?

what have you EVIDENTLY learned from previous wells wrt this daily. This is surely where the opportunity is to learn. 

With all the evident specifics needed it is difficult to offer required best practices that may or may not work. 
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