Well Integrity Technical Section

Hi all,

One of the used method to confirm the casing integrity is applying a pressure down the casing up to 70% of the working pressure. And the question that I have is doing this kind of test on a legacy well could reduce from the casing integrity or not.

And what are the conditions should be considered for the casing integrity if it's required to perfume on a new well / and on legacy one too?

Thx

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Dhyaa Y.
"This comment / post reflects a purely personal opinion and not that of the organization with which I am affiliated."
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I suppose you have already heard this.

As long as the casing integrity is such that no point exceeds the elastic
limit during the process, it should be ok/

70% working pressure is a method that reduces risk, but it does not
guarantee success.

If there is any question of well integrity, casings that are accessible
should be logged with a casing integrity tool. Although not foolproof, it
is the best current method for assuring that you don't deform or damage
anything.

For inaccessible casings, you will have to rely on field histories of
corrosion and other damages and make an estimate. This much less useful,
but better than nothing.

Performing well integrity test requires more than just testing to 70% of the casing envelope.
In addition to the casing properties (metallurgy,  burst and collapse) it  requires to know the cement type behind it, the condition of the set  cement and the pressure envelope it can sustain the cementing service provider will be able to give these parameters, a quick simulation will reveal whether the applied pressure can be withstood by the casing and the cement behind it (especially the cement, as you may destroy the bond between the casing and the cement or cracks the cement due to high radial stresses from the pressure test). 
As a result I recommend that:
1. Cross check with the cementing service provider the pressure envelope the cement can withstand, use the pressure test value as an input and check whether the cement stays intact
2. If tge cement is OK then you should be safe to proceed
3. If not ( set cement cracks or debonds) then you may consider lowering the pressure test value to stay safe.
I hope this helps
SALIM TAOUTAOU

------------------------------
Salim Taoutaou
TCOFS
STAOUTAOU@TCOFS.COM 

Caution; even a well cemented annuli adds very little strength to casing.

See the paper SPE-139766


Original Message:
Sent: 1/15/2023 12:51:00 PM
From: Salim Taoutaou
Subject: RE: Casing Integrity Test

Performing well integrity test requires more than just testing to 70% of the casing envelope.
In addition to the casing properties (metallurgy,  burst and collapse) it  requires to know the cement type behind it, the condition of the set  cement and the pressure envelope it can sustain the cementing service provider will be able to give these parameters, a quick simulation will reveal whether the applied pressure can be withstood by the casing and the cement behind it (especially the cement, as you may destroy the bond between the casing and the cement or cracks the cement due to high radial stresses from the pressure test). 
As a result I recommend that:
1. Cross check with the cementing service provider the pressure envelope the cement can withstand, use the pressure test value as an input and check whether the cement stays intact
2. If tge cement is OK then you should be safe to proceed
3. If not ( set cement cracks or debonds) then you may consider lowering the pressure test value to stay safe.
I hope this helps
SALIM TAOUTAOU

------------------------------
Salim Taoutaou
TCOFS
STAOUTAOU@TCOFS.COM 

Hi Dhyaa,

Firstly, in the case of a 'new' well;  pressure testing can be done up to a reasonable percentage of the working pressure, given considerations to (i) WP's of both joint type and pipe body, (ii) the type and maximum pressures to which the pipe will be subjected to in it's lifetime, and (iii) surface equipment.  eg, is it an injector, a producer, oil and/or gas, on pump or exposed to reservoir pressures, HP or LP, will it be fractured, and so on.  Provided pressures don't exceed a prescribed % of the yield strength of pipe or joint, should be fine, ie, no theoretical damage to pipe. 

The qualifier to this however: applying pressure to the string will of course tend to expand slightly, hence potentially causing a micro-annulus, or worsening an existing one, with associated problems later.

In the case of an existing well, the entire workover program should include all of the above, but additionally add considerations to several ore things, such as…

(i) the production (or injection) history of the well, including such factors as corrosion, pressure & thermal cycling.

(ii) if the well is being "re-purposed" (for example, conversion from producer to injector, or re-completed in a new zone), consider all the factors for a new well along with those for re-entry, use those which apply most conservatively.

(iii) the age of the well, including any issues noted during production/injection, leaks, pressure anomalies, presence of scales or asphaltenes that may affect P-test results, and so on.

(iv)  if any corrosion is suspected, consider de-rating the string – hence also lowering the pressure test to something less than 70%, that will avoid irreparable damage to the string.  This of course assumes no need for this much pressure under the wells 'new' condition.

As noted by others, there are means to evaluate the casing condition if it's at all questionable. 

This may not answer your question directly but will hopefully provide some food for thought in arriving at a path forward.

Good luck….

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Scott Myers
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Interesting discussions.  I will point out a couple of historical things through my career with majors and running a consulting business.  

1)  My legacy company, that had some of the best engineering manuals and standards in the business (so good, that Royal Dutch Shell purchased them in the early 80's), had an 80% pressure/burst limit and 1.6 safety factor on connections on "new casing".
2)  One of my early projects (along with my full time job in Denver doing contracts and rig bids) was to figure out what was happening to a group of wells in SW Wyoming:  Casing leaks following frac jobs that were conducted at lower pressure than the 80% of yield number.

In those days, we didn't have the sophisticated casing design program Amoco later developed and I was using a "Baker Oil Tools" tubing design process in the back of one of their catalogs!  (this was 1977-78 era).  My conclusion and what proved out in practice was even though the frac fluids were heated to 50ºF (to get the gel to properly disperse), that cool frac fluid during a massive hydraulic frac job was cooling the casing to the point the connections were well below the 1.6 safety factor and we were probably deforming the threads and losing the seal.  (As I recall, the BHT was ~275F)

Solution:  We moved from 32# N-80 casing to 28# P-110 casing (after I convinced the "non-driller" district manager that the P-110 wouldn't crystalize and shatter in sub-freezing temperatures (I remember several days of less than -30F in the area).  The joint strength was about the same but the lighter load and less mass due to the lighter weight was all that was required to stop yielding the threads on the connections!  Problem solved.

It worked!  (Thank you Baker Oil Tools for the workbook!)

Doug White
Sugar Land
Original Message:
Sent: 01-16-2023 01:59 PM
From: G Myers
Subject: Casing Integrity Test

Hi Dhyaa,

Firstly, in the case of a 'new' well;  pressure testing can be done up to a reasonable percentage of the working pressure, given considerations to (i) WP's of both joint type and pipe body, (ii) the type and maximum pressures to which the pipe will be subjected to in it's lifetime, and (iii) surface equipment.  eg, is it an injector, a producer, oil and/or gas, on pump or exposed to reservoir pressures, HP or LP, will it be fractured, and so on.  Provided pressures don't exceed a prescribed % of the yield strength of pipe or joint, should be fine, ie, no theoretical damage to pipe. 

The qualifier to this however: applying pressure to the string will of course tend to expand slightly, hence potentially causing a micro-annulus, or worsening an existing one, with associated problems later.

In the case of an existing well, the entire workover program should include all of the above, but additionally add considerations to several ore things, such as…

(i) the production (or injection) history of the well, including such factors as corrosion, pressure & thermal cycling.

(ii) if the well is being "re-purposed" (for example, conversion from producer to injector, or re-completed in a new zone), consider all the factors for a new well along with those for re-entry, use those which apply most conservatively.

(iii) the age of the well, including any issues noted during production/injection, leaks, pressure anomalies, presence of scales or asphaltenes that may affect P-test results, and so on.

(iv)  if any corrosion is suspected, consider de-rating the string – hence also lowering the pressure test to something less than 70%, that will avoid irreparable damage to the string.  This of course assumes no need for this much pressure under the wells 'new' condition.

As noted by others, there are means to evaluate the casing condition if it's at all questionable. 

This may not answer your question directly but will hopefully provide some food for thought in arriving at a path forward.

Good luck….

------------------------------
Scott Myers
------------------------------

Hi Dhyaa,

Without complication of the subject, I would consider 2 things: 

- Max pressure that casing is expected to be exposed in rest of his life (i.e. thermal expansion, formations pressure, potential stimulation jobs) 
- Current condition of the casing

But remember, devil in details. 

Thanks,
Tural

Hi Dhyaa,

For a new well, I recommend you to review the Casing Design study report (ask your asset manager or head of drilling engineering) for you to assess how detailed the different loads cases considered have been addressed in terms of hypothesis, and if the considered load cases cover the complete well life-cycle, drilling, exploitation, WO, up to P&A. If the document is complete you should also find recommendations on casing string integrity pressure testing for different scenario (drilling, WO, depletion range, range of cement top, range of annulus mud weight and sagging with time, range of temperature well shut in / well producing / well bull-heading, fracking, etc). You could then pick an educated pressure testing range adhoc for you subject well. Like many said there is no rules applying for all, well design criteria and well history are instrumental.

An additional point on well history is the Well Handover document for new wells from Drilling to Production upon drilling and completion execution. This document summarizes the production operating parameters for the well in terms of maximum pressure build-up allowed in every annulus and within the completion string, how much and how to bleed-off when necessary and associated procedures where applicable, how to shut the well in and how to put it back on stream. Required regular maintenance on the well-head and valves are described too. This document highlights any issues occurred while drilling that could negatively impact the initial well and casing design and its design criteria, and mitigation measures to comply with are described. The Well Hand-Over document is updated after each WO and well intervention (slick line, pumping, etc) if need be.
Original Message:
Sent: 01-17-2023 11:41 AM
From: Regis Studer
Subject: Casing Integrity Test

Hi Dhyaa,

For a new well, I recommend you to review the Casing Design study report (ask your asset manager or head of drilling engineering) for you to assess how detailed the different loads cases considered have been addressed in terms of hypothesis, and if the considered load cases cover the complete well life-cycle, drilling, exploitation, WO, up to P&A. If the document is complete you should also find recommendations on casing string integrity pressure testing for different scenario (drilling, WO, depletion range, range of cement top, range of annulus mud weight and sagging with time, range of temperature well shut in / well producing / well bull-heading, fracking, etc). You could then pick an educated pressure testing range adhoc for you subject well. Like many said there is no rules applying for all, well design criteria and well history are instrumental.