Well Integrity Technical Section

Hi all,

We're looking at some wells where, due to weak sands, building a significant column of cement above the reservoir will be challenging.  We'll be able to isolate the zones but its uncertain whether we can build a tall enough column to put cement across the production packer setting interval.  Obviously, the packer performance envelope may be lessened in unsupported casing but in reviewing integrity docs like ISO 16530-1 and NORSOK D10, I'm surprised that I'm not seeing any guidance in this regard, as there is an annulus around a primary barrier ... a casing leak below the packer would be a mess. 

Is this something that is accepted, or am I looking for guidance in the wrong places?

Thanks,

R

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Ron Nelson
Subsea Completion Consultant
ron@deep-blue.ca
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Hi Ron

Had a similar experience recently and could not find any thing definitive either.  Then you end up down the risk assessment path

1. Do I need to log it and how much cement is required to isolate the zone (see NORSOK) 
2. Consequences of the fail - the packer leak scenario !  That's all about the previous shoe
3. Do I have monitoring ?
4. Can I bleed my annulus ?

My recent example was subsea well with a weak previous shoe .. then it wasnt so much about the packer as the consequence of the failure of the casing below the packer

Ian

Hi Ron,

NORSOK D-010 agrees with your "mess" scenario. Table C.7.C.2 requires that "any leak through the casing below the packer, will be contained by the well barrier system outside the casing, i.e. the packer shall be set below a verified annulus Well Barrier Element". And then it mentions "annulus seal (e.g. cement)".

The barrier requirement is fair enough: any leak through the primary, which includes production casing and packer, must be fully contained by the secondary. Insisting on an annulus WBE and mentioning cement explicitly is a bit more puzzling: typically, the annulus barrier element is the wellhead, not a lower seal (especially not cement).

If you look at all well barrier diagrams in the standard, you will see shaded (i.e., qualified) cement across the packer. This is a bit misleading, since you qualify cement to cross the annulus at the depth of the caprock, and then use the production casing - an inside-out barrier element - to climb up to the packer. But the meaning is clear: even if you don't have 30-50 m of defect-free cement above the packer, just by ensuring a bit of good cement you mitigate a major leak (and a major accident scenario) outside of your casing. So if you leave the production casing uncemented you do not impact your barrier system, which is based on probability of failure, but increase the severity of a leak and thus the risk.

In short, you can claim compliance with the letter of NORSOK D-010 as long as you qualify the secondary barrier. But you may want to follow the spirit of the standard and set the packer across a cemented annulus (which is required for injectors anyway).

By the way, in my experience this setup will be a nightmare to abandon: nobody wants to mill a packer, so you're looking at qualifying one or two annular barrier elements a safe distance above it. This means a top of cement >100 m above the packer setting depth to have a passing chance of success. How do you plan to abandon the well, knowing that regulations may not become looser in 20-30 years?

Best regards,

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Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
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If you are worried about a good column of cement above your pay zone, you need to talk to your drillers (of which I am one) to do a better job and/or remedial work to get a good isolation of cement above the pay.  

This being said, I think just good engineering (much less regulations) would not want a production packer above the external top of cement.

Doug White

Sugar Land

The short answer is that you should not plan on setting a packer in un-cemented casing.  A casing leak below the packer would be un-detectable and lead to a flow path on the outside of the casing past the packer.

For containment reasons, you need to have cement in the caprock.  If your design doesn't let you set a packer there, you should reconsider your (completion, casing, cementing) design. 

If something went wrong during construction, that is a different story, as you are now managing risk, and trying to make the best of a bad situation.

Packers have a casing ID range they are designed for.  as long as the casing expansion falls within that range the packer should work just fine.

I have seen a case where the slips on frac plugs cut the casing and parted it.  That was a rare occurrence with high frac pressure (and thus high treating pressure) with low pore pressure (backup pressure).  Once we realized what had happened, it was fairly easy to verify with calculations....

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Hans-Jacob LundConocoPhillips Co
Principal Well Integrity Engineer
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Hi Ron,

You just stepped into a very "gray" area

This is a very good question!

So, this is from a Production Technologists perspective

1.      Cement across the reservoir section (production casing) is critical barrier element for long term well integrity and isolation. If the HC starts flowing up past the caprock and ends up in another reservoir above the caprock, we in effect have a uncontained underground blowout and at the least a severe reserve/allocation problem.
So, from a production engineers perspective, good cement isolation (at least up to the caprock), is a basic requirement.
In so many instances, I have seen drillers walk away from this type of a problem but I have to eventually perform a workover after they are gone to ensure reservoir integrity.

2.      After spending significant time on MOEP (maximum Operating Envelope pressures) calculations during the well production phase, I discovered that the envelopes do not take into account the cement quality/strength, when calculating the A annulus operating envelope.
The packer- A annulus- Tubing- TH seal- Production casing envelope is solely based on the metal components.
So, in your case, what does it matter if you have cement across the packer setting depth, you can't prove it value anyway?
It may be a nice to have, but not necessarily a requirement, I suspect this is why the Norsok D10 is vague on the subject.

3.      There are government regulations that state that the production packer must be set across the caprock. I am still not clear why.
The production packer is inside the production casing and its working envelope is based on the strength and integrity of the production casing.
What it matter where its set?
The cement on the outside of the production casing must reach the caprock and its integrity verified but I am still trying to understand how the production packer set at the caprock and cement up to the caprock are connected barrier elements.

I suspect these requirements got "lost in translation" somewhere.

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Basker Murugappan
Principal Production Technologist
Villalbilla, Spain
+34 644485970

Three basic rules:
1) Change is inevitable.
2) Everybody resists change.
3) You cant stop change
------------------------------

If there is concern about not getting a sealable cmt above a production zone, a thought would be also to run a couple of Halliburton's swell pkrs above your hydrocarbon zones.  With time, the packers can "swell" and help prevent hydrocarbon or high pressure water movement along with the cement column and a hshort set time on the gel set time of your cement slurry (possible two stage job with gel time controlled!

Rick

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W. R. "Rick" Farmer, P.E., SPEC
Managing Partner
Double R Engineering, LLC
Lafayette, LA
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Original Message:
Sent: 06-11-2024 01:02 PM
From: Basker Murugappan
Subject: Production Packer Set Above TOC

Hi Ron,

You just stepped into a very "gray" area

This is a very good question!

So, this is from a Production Technologists perspective

1.      Cement across the reservoir section (production casing) is critical barrier element for long term well integrity and isolation. If the HC starts flowing up past the caprock and ends up in another reservoir above the caprock, we in effect have a uncontained underground blowout and at the least a severe reserve/allocation problem.
So, from a production engineers perspective, good cement isolation (at least up to the caprock), is a basic requirement.
In so many instances, I have seen drillers walk away from this type of a problem but I have to eventually perform a workover after they are gone to ensure reservoir integrity.

2.      After spending significant time on MOEP (maximum Operating Envelope pressures) calculations during the well production phase, I discovered that the envelopes do not take into account the cement quality/strength, when calculating the A annulus operating envelope.
The packer- A annulus- Tubing- TH seal- Production casing envelope is solely based on the metal components.
So, in your case, what does it matter if you have cement across the packer setting depth, you can't prove it value anyway?
It may be a nice to have, but not necessarily a requirement, I suspect this is why the Norsok D10 is vague on the subject.

3.      There are government regulations that state that the production packer must be set across the caprock. I am still not clear why.
The production packer is inside the production casing and its working envelope is based on the strength and integrity of the production casing.
What it matter where its set?
The cement on the outside of the production casing must reach the caprock and its integrity verified but I am still trying to understand how the production packer set at the caprock and cement up to the caprock are connected barrier elements.

I suspect these requirements got "lost in translation" somewhere.

------------------------------
Basker Murugappan
Principal Production Technologist
Villalbilla, Spain
+34 644485970

Three basic rules:
1) Change is inevitable.
2) Everybody resists change.
3) You cant stop change
------------------------------