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High angle surface casings
13 August 2018

Hi All,

I'd like to know what the experience has been designing and drilling shallow extended reach horizontal wells, resulting in high angle surface casings: > 50 degs. This kind of design has been utilized successfully in a couple of wells in the past (before my time) but I'm wondering what kind of risks /areas of concern this would introduce as there is limited information on the older wells.

A summary of the project I'm looking at is as follows:

The project is an infill drilling project from a platform located in circa 32ft-md of water. All the conductors have been pre-installed and at depths 500 - 600 ft-MD. The depths for the reservoir targets are circa 3000ft - 3300TVDss and these have a step out distance from the platform of circa 6000 - 9000ft MD. To achieve the horizontal trajectory design (aligning both the heel and toe), the inclination needs to built quite aggressively from the surface section. Currently the trajectories have been built with 1 - 4.5 deg/100ft in the surface section and slightly higher in the subsequent hole sections. A dril-quip surface well head system: the dual bore 2 step unitized wellhead, is to be utilized for the project.

My main concern is the consequence of the very high surface casing inclinations and the impact on the overall well design. Besides casing wear are there other risks I should be looking at? If so how were these risks mitigated or eliminated. In addition is there any rule for max surface casing inclination.


7 answer(s)
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 361
Join Date: 10/01/05
Chike,

(Relevant experience/case studies from some while ago that may help/assist as enclosed)

Hazard/ Risks?: When one is in shallow very drillable formations and wanting to build angle. 

It can be difficult to drill optimally and hold and build angle if the right bit/BHA/practices are not used and applied.  (Note: Regional knowledge and experienced will play a large part)   

Bit/BHA/practices.

PDC may not be the ideal choice for building angle? and delivering optimal results in shallower directional applications?. e.g. Roller cones are commonly the best choice!

As offered and concluded from attachment where we ran the same roller (bi-cone) bit on seven wells (drilling 14,609 ft in total averaging 303ft/hr)!

Note: The reason for running a roller cone bit? was not primarily for optimal ROP, but was to  reduce time spent sliding and to be able maximise rotary and directional drilling capabilities. (as this is where most value, risks were to be had and existed in our view)

We ran the bit first on an exploration vertical well to prove it could match tri-cones being run. This proved, we then ran this on a series of directional development (slender) subsea wells where we started to build angle below the 30in conductor shoes. 

As stratigraphy was sand dominant? We first batched drilled conductors and then ran the subsea bop to use this as a conduit to drill with a weighted mud solution. (versus riserless drilling)

As per Scots email we adopted a catenary shaped well and maximum angle was in fact only 20deg at 13 5/8" section depths. (intervals ranged from 814 ft to 2291ft). In this case going higher would have require >mud weight and determining where casing had to be set to prevent wellbore instability from resulting.

The feedback from the DD's was that the roller cone (bi-cone) achieved what was expected. i.e. far less sliding (versus offset data mud logs) was experienced allowing maximum rotational time and far greater delivery value.

Motor vs RSS (pros/cons)? 
As enclose this can be achieved safely and optimally with a motor and a bent sub. Ideal Bit/BHA delivery is drill 20-30ft, slide 15-20ft, then rotary drilled for remainder of stand. If there is demonstrable risk? 

Pros/cons of RSS then discussed to demonstrate where most value can be added. 

Connection Risk?: It is easy to loose angle if one messes around on connections. (e.g. Using the 'B' word? note: we required none of this on wells shown, period!.) Stop rotation, pick up 10-20ft, if drag and driller was satisfied connection was made. The simply tried and tested old fashioned way!

End result: On all wells bit/BHA were POH on elevators with no major wellbore issues recorded. Section 'picking up BHA to running tool pulled after cementing', delivery was best in class by a long shot, for region. 





  
Documents uploaded by user:
Shallow directional drilling..pdf
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 361
Join Date: 10/01/05
Chike, 

Besides casing wear are there other risks I should be looking at? If so how were these risks mitigated or eliminated. In addition is there any rule for max surface casing inclination.

What not yet highlighted is the importance of Geology/geoscience understanding. 
This is central to each and every set of well plans/engineering required. Ask yourself, What are you drilling through?
The two boundary conditions limits I generally consider for SE Asia environments (as exemplified in the Wentworth scale attached) are:

100% shallow Clay drilling intervals that are the most tolerant to angle vs sand for example. (Ref. Wentworth scale attached)

Case study: Jack up in 90's; supervising a 17 /2 wellbore offshore Malaysia directionally drilling (with a motor and bent sub) at 200-250ft/hr** (with seawater) building up to 55 deg drilling 100% clay to approx. 5,500ft AHD (3000ft TVD). Note: Only grey water being observed at shaker (as clay disperses). At section depth rig displaced to a simply 9.3ppg WBM, POH on elevators to then run and cemented casing.

Key point if clay is fractured often a fracture extension can and will result. So its not the end if a pack-off etc event should and can result.

**Drilling rate was limited as Rig had limited pump rate and this was driving max permissible ROP before 4-6% cuttings concentrations (issues would result). > than 4-6% concentration soft clay problems (mud rings, balling, pack off etc) thereafter can typically result.

IN CLAY dominant sections (as typically drilled in SE Asia) high angle with fewer casing string wells (slender wells) are often feasible and readily drilled.

Drilling 100% Sand is the flip side of tolerance to clay. (Ref Wentworth scale attached). This cannot generally be drilled with seawater alone. If sand is fractured it cannot be healed
There will a defined limit (angle) therefore to what each section interval will take. General rule of thumb for mud weight is also that 0.5ppg per 30degress of inclination is needed. 

So in the same 17 1/2" wellbore as case study above, one would need to drill with a mud system and build weight in small step-up -stages as wellbore inclination increased (to combat sand instability.) At a safe threshold value casing would need to be run and set.    

Bottom line is more casing strings are likely required or mud weight and wellbore stability management needs to be fully understood.  

Hole size is critical. 
For example 26in and 17 1/2" wellbore are two completely different sets of challenges. 17 1/2" generally more favourable at a lot less risk. So one again has to know understand and be able to work out where drilling operating, tripping limits etc are? 

Best planning engineering and well operating delivery practices?
For all of the above People and best practice are central to the successful delivery of these wellbore as planned. Try and find a best in class well and one where problems resulted and try and figure out why one succeeded and why other failed. note: Mud /drilling logs generally provide all the answer so try and get a hold on these.

Peer review /assist.
Once you have a base case plan get a peer to review and assist accordingly.

Wishing you every success.

 
Documents uploaded by user:
Wentworth-Grain-Size-Chart.pdf
bennyfmc
Drilling Engineer
SPREADAssociates
Total Posts: 10
Join Date: 03/03/16
We've been work also with ERD well that require inclination from the conductor in order to create less DLS on below. What we've been using is Deviated Drive Shoe. Frank's Hammer services can support you with the equipment.

Basically its a drive shoe that have some offset so it will create inclination as you drive it. Some issue need to consider are :

1. Need to adjust the direction before you drive it. Usually we ask DD to orient it.
2. You can control the DLS. Some it goes smooth, some it creates high DLS. Depend on your soil.
rollintr1
Drilling & Completions Advisor
SPREADAssociates
Total Posts: 5
Join Date: 17/05/15
I am curious to what fluid you are using to drill these wells - would think it would be an ideal project  (dependent upon density) for a formate brine which would provide an environmentally lubricious fluid.
Scott_McNeil
Consultant
SPREADAssociates
Total Posts: 110
Join Date: 05/03/08
Hi Chike,

A few thoughts from a project I worked on many moons ago, where we regularly set surface casing at up to 60 Deg;

Work closely with your Drilling Contractor and Drill String Inspector to make sure you have hard banding on the DP & HWDP that will minimise casing wear - there are several types to choose from.

Minimise the number of trips. On that project, we found that casing wear was more due to tripping than rotating and we could clearly see grooves on casing wear logs from this.

It should go without saying, but keep the well bore trajectory as smooth as possible - no sudden dog legs (a lot easier to do these days with RSS).

Despite high build rates and worryingly large amounts of metal shavings being recovered from the ditch magnets, we found that casing wear was actually minimal.

There would be an initial spike in ditch magnet readings which was generally down to casing burrs & rust being knocked of the inside, and then it would settle down to a relatively low 'background' reading.

Going sideways a second, make sure the Mud Loggers clean and weight the ditch magnets at regular, short intervals. Ditch magnets will only hold so much metal before any shavings in the mud cannot get captured by them, so if the crew don't clean them often enough, you can get false 'low' readings.

Anyway, on one particularly difficult well, we ended up with a profile that, in 6,000', at every point we were trying to build / turn / drop with a DLS of at least 3 Deg / 100'. Despite several hundred rotating hours (the reservoir section was extremely hard), we found that casing wear was substantially less than expected on the wear logs.

One thing we didn't do (because the technology didn't really exist then) was to consider catenary type well profiles - i.e. the profile an anchor chain from a moored Semi sub adopts.

In these cases, the required build rate starts off very low and continually increases towards TD. By doing this, it ensures the sideforces are minimised and relatively constant throughout the length of the wellbore.

I think Equinor (Statoil) have done some SPE papers on this type of profile?

Further to Peters comment, the last needs everyone in the office and on the Rig to be well briefed on the plan and why this is being done before hand. Otherwise it is too easy for the rig crew to feel they can get a better build rate and get 'ahead of the curve' at the start of the build program.

Further to Waynes comment, I would recommend avoiding using DP rubbers. We actually found that they would increase casing wear, as metal particles would get embedded in them and they'd act like a downhole lathe.

With the problems caused by debris when they came off (almost inevitable), we actually stopped using them early on in the program and I haven't used them since.

All the Best

Scott
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 361
Join Date: 10/01/05
Other risks I should be looking for?

Note: Drilling failure in these type of wells evidently results from poor pre-planning not getting all disciplines needed involved and lack of attention to the more in depth and detail of work needed to be done sooner rather than later.


rockbit
Consultant
SPREADAssociates
Total Posts: 18
Join Date: 31/07/11
I would be very concerned about casing wear. Sacrificial drill pipe rubbers will help, but increase torque exponentially. Non rotating stabilizers would be better. 
The drill sting design inside, and outside the casing will be very different, and may require trips to refresh, as the well deepens.
just my thought, shooting from the hip...
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