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Blast joint placement criteria
10 January 2020
We are planning workover for the existing multiple zone gas well with dual strings. 
The plan is to develop a new lower zone and complete it and existing upper zone with dual strings (13Cr).   
According to the rule of thumb, we should put blast joints in long string (highlighted in red in attached file) to cover the upper zone completion section.

However, we are not sure we should do that with considering the short field life like ~6yrs and the low productivity of the upper zone which is known like ~50k Sm3/d. 
We doubt such a gas rate would erode the 13Cr material severely and would like to use normal 13Cr tubing instead from the economical point of view if feasible.

Q1. Is there any criteria to define if we should apply the blast joint (production rate, tubing material, size,..)?

Q2. Is there any criteria how long additional length of the blast joint should we put against the completion zone?

Please help...thank you very much!
Documents uploaded by user:
Well schematic.PNG
6 answer(s)
GordonDuncan
Technical Director / Trainer
SPREAD Associates
Total Posts: 6
Join Date: 31/03/20
if you have blast joints use them across the perfs only, if no blast joints do you have Flow Couplings available

Plan for the worst, if there is no solids, no issue, as soon as you get water you will get sand therefore erosion and subsurface always want to produce till the end
using correct equipment will prolong the life of the well and make for recovery and eventual P&A much easier
Hiro
Well engineer
Japex
Total Posts: 4
Join Date: 03/12/19
Dear Dan, Fabrizio, Ritthy, Brian,

Thank you very much for your quick and valuable answers.
We will consider your answers.

Best Regards,
Hiro
Brian24001
Well Intervention and Integrity Engineer
TOTAL
Total Posts: 3
Join Date: 20/06/19

Consider the phase. If you are in liquid phase, will you actually see any appreciable influx velocity, I suspect not.

Also consider total perforation area. Does it exceed the minimum down hole ID. If it does, again little if any velocity due to DH choke (at potential max rate).

But overall, aside from a small cost, and a minor handling issue, and if there are any concerns, is there a significant downside to blast joints, I suggest not.

You mention cost - is 13Cr necessary? Big potential saving in the overall metallurgy selection for a 6yr well.

Just make sure you give yourself sufficient contingency options in case you need to set a BP in the area at a later date, and more so build in tubing options for a tubing cut later if needed, bearing in mind that if you do produce enough solids to have needed the blast joints, and if the lower packer is 'pull to release' you may loose the release/recovery option due to sand packing.

Cheers,

Brian

rson
Drilling Engineer
SM Energy
Total Posts: 7
Join Date: 01/10/18
Dear members,

If memory serves, from his work at Amoco Production Research - George E King published SPE papers on important considerations for tubulars (alloy, necessary thickness) depending on your perforation strategy - of related note was blast joints.

One of the (many) insightful pieces from his completions/perforation work was determining with lab scale testing on casing that you could aggressively perforate with tight phasing up to 16 shots per foot and with minimal loss of axial strength and crush resistance.

This is considering 80s-90s the guns/charges technology for the given penetration hole size (no mention of "deep penetrating", i.e. explosives amount, or shaped charges that I recall).

Depending on Hiro's circumstances (high pressure gas, acid gas?), surely there are blast joints with specialized connections (gas tight?)... but another thing to consider is what formation penetration depth they are trying to achieve and maybe what guns are (economically) available to run on tools which will drift through the blast joints (assuming the OD was modified).

If there's any chances of shutting off/squeezing some of those comingled zones over the 6 years, that might appreciably change the conversation too.

Check out SPE-18843-MS

I hope it helps

Ritthy
FDellaLucia
Drilling Manager
SPREAD Associates
Total Posts: 3
Join Date: 16/02/13
Dear Hiro

In my experience, the use of blast joints placed across the producing zone was considered if solids (i.e. sand) production is foreseen. 

In a conventionally completed zone (i.e. without sand control), this phenomenon could occur as a result of the depletion of the production zone, which could lead to an increase in water production. 

As for the erosional velocity estimation in ‘clean service’ (i.e. in an environment without impurities where the erosion could be caused by the liquid droplets), I would like to suggest to review the SPE Paper 170951-MS (2014).

I hope it helps

Fabrizio
Dan
Workover Engineer
SPREAD Associates
Total Posts: 16
Join Date: 01/08/18
Hiro,

1. As a rule of thumb, under most conditions dry gas does not erode steels harder than N-80. 

2. Tests conducted on surface lines showed that at an impingement angle of 10 degrees or less, the erosion wear for a hard, brittle material is essentially zero. The maximum wear rate occurred when the impingement angle was between 40 and 50 degrees. The wear rate increased when the solids in the slurry were harder than the tubular surface. Sand is slightly harder than steel. Barite is much less abrasive than hematite.

3. If the blast joint availability is an issue it might worth to consider installing of a polished nipple below the bottom of perf and a landing nipple above the top of perf. Regular tubing wall thickness logs shall be conducted after first year. 

I hope this will help you.

Dan


Posted by

HIRO KONO

Well engineer

Japex

Total Posts: 4
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