Well Integrity Technical Section

Dear community,
I am new in Well Integrity and would like to ask if there is already an
established practice of evaluating tubular corrosion progress and
forecasting corrosion trend by means of several corrosion logs?
I have two corrosion logs ran in the same well at a distance of years and
would like to calculate the corrosion trend to forecast the time for
repeating the corrosion log or planning a well intervention. How is this
usually done?
Thank you!

Hi Enis,

You just opened a can of worms.
The easiest approach, if your pipe is bound to fail through burst (say, a tubing), is to take the minimum wall thickness at each depth and then extrapolate linearly to the minimum allowable wall thickness for a given overpressure.

This approach is also not terribly correct, since localized corrosion - say, at a particular azimuth or in a patch - is not as bad as uniform wall thickness lost: the intact steel will provide some support to the damage area.
If you're really into advanced approaches, I would grab a copy of API 579-1 Fitness For Service: excellent standard that will guide you through a properly structured method. You may also want to get hold of Boiler & Pressure Vessel Code (BPVC) cases, in particular N-806 to account for non-uniform metal loss.

There are other ways to extrapolate measurements to all wells in a field.
As for the time to repeat a corrosion log, you're looking at a Reliability Centered Maintenance (RCM) approach. You could also, even though it is "illegal", apply API RP 581 Risk-Based Inspection. Both rely on a cost vs. risk approach to schedule the next inspection, a log in your case.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
------------------------------

Hi Matteo,
I appreciate your answer.

According to DNV (DNV-RP-F101 & DNVGL-ST-F101), the effect of localized corrosion on tubular resistance is not as important as the effect of general corrosion. DNV also indicates a method that accounts for all localized corrosions, say in a circumference of the tubular. I have used the DNV approach to average out all circumferential localized corrosion for each depth step of the corrosion log. With this I can calculate the resistance of the tubular at each depth step.

Now, the question is: has anyone used two corrosion logs of the same well, conducted at a distance of several years, to evaluate the rate of corrosion and, from there, to predict the future corrosion state of the tubular (assuming linear corrosion with time)? If so, how?

Thank you,
Enis Aliko
____________________
enis.aliko@wellynx.com

------------------------------
E.Aliko
------------------------------

Original Message:
Sent: 10-18-2022 06:07 AM
From: Matteo Loizzo
Subject: Tubular corrosion evaluation

Hi Enis,

You just opened a can of worms.
The easiest approach, if your pipe is bound to fail through burst (say, a tubing), is to take the minimum wall thickness at each depth and then extrapolate linearly to the minimum allowable wall thickness for a given overpressure.

This approach is also not terribly correct, since localized corrosion - say, at a particular azimuth or in a patch - is not as bad as uniform wall thickness lost: the intact steel will provide some support to the damage area.
If you're really into advanced approaches, I would grab a copy of API 579-1 Fitness For Service: excellent standard that will guide you through a properly structured method. You may also want to get hold of Boiler & Pressure Vessel Code (BPVC) cases, in particular N-806 to account for non-uniform metal loss.

There are other ways to extrapolate measurements to all wells in a field.
As for the time to repeat a corrosion log, you're looking at a Reliability Centered Maintenance (RCM) approach. You could also, even though it is "illegal", apply API RP 581 Risk-Based Inspection. Both rely on a cost vs. risk approach to schedule the next inspection, a log in your case.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
------------------------------

Hi Enis,

There are a number of ways to predict the residual life of a casing string.
The one you're referring to consists in calculating a local corrosion speed, and then use it to extrapolate linearly to failure. Whereas it is safe to assume that corrosion will progress linearly, there are two issues you have to deal with:

• A lot of corrosion is localized, most often along a specific azimuth. So, either you compare the thickness (or inner radius) maps after depth-matching and alignment, or you compare the minimum thickness at each depth after depth-matching. Trouble is, the point with minimum thickness now may not be the same as, say, 10 years ago. So you need to ensure that your corrosion patterns repeats, and that you get rid of all "bad" points that affect minima but not averages (high-frequency ultrasonic logging tool seem to be more prone to artifacts).
• The residual life depends on when you reach the safe operating limit, which will depend on the geometrical distribution of wall thickness. If you have a map of corrosion, then you can extrapolate the whole map. If you use the minimum, you may need to make assumptions about the shape evolution. If DNV gives you a maximum stress as a linear function of the minimum thickness, then you can extrapolate the maximum stress directly. If you want a very conservative approach, then you can extrapolate the minimum thickness and compare it to API formulas.

Another way to estimate residual life is using the statistical distribution of time-to-failure for previous tubulars. That will give you a, say, normal distribution of corrosion speed that you can then extrapolate to every other well in your field. Works like magic for wetted pipes, like completion tubing. And it doesn't require logs, since you can get the exact time-to-failure from annular pressure - even though measurements can also be incorporated in this statistical approach.

I must say that your question looks deceptively simple: you seem to suspect that something is not right with the standard extrapolation approach. Maybe you could state your (or your client's) doubts directly?

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
------------------------------

Original Message:
Sent: 10-25-2022 02:08 AM
From: Enis Aliko
Subject: Tubular corrosion evaluation

Hi Matteo,
I appreciate your answer.

According to DNV (DNV-RP-F101 & DNVGL-ST-F101), the effect of localized corrosion on tubular resistance is not as important as the effect of general corrosion. DNV also indicates a method that accounts for all localized corrosions, say in a circumference of the tubular. I have used the DNV approach to average out all circumferential localized corrosion for each depth step of the corrosion log. With this I can calculate the resistance of the tubular at each depth step.

Now, the question is: has anyone used two corrosion logs of the same well, conducted at a distance of several years, to evaluate the rate of corrosion and, from there, to predict the future corrosion state of the tubular (assuming linear corrosion with time)? If so, how?

Thank you,
Enis Aliko
____________________
enis.aliko@wellynx.com

------------------------------
E.Aliko
------------------------------


Original Message:
Sent: 10-18-2022 06:07 AM
From: Matteo Loizzo
Subject: Tubular corrosion evaluation

Hi Enis,

You just opened a can of worms.
The easiest approach, if your pipe is bound to fail through burst (say, a tubing), is to take the minimum wall thickness at each depth and then extrapolate linearly to the minimum allowable wall thickness for a given overpressure.

This approach is also not terribly correct, since localized corrosion - say, at a particular azimuth or in a patch - is not as bad as uniform wall thickness lost: the intact steel will provide some support to the damage area.
If you're really into advanced approaches, I would grab a copy of API 579-1 Fitness For Service: excellent standard that will guide you through a properly structured method. You may also want to get hold of Boiler & Pressure Vessel Code (BPVC) cases, in particular N-806 to account for non-uniform metal loss.

There are other ways to extrapolate measurements to all wells in a field.
As for the time to repeat a corrosion log, you're looking at a Reliability Centered Maintenance (RCM) approach. You could also, even though it is "illegal", apply API RP 581 Risk-Based Inspection. Both rely on a cost vs. risk approach to schedule the next inspection, a log in your case.

Best regards,

------------------------------
Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany

Hi Enis, 
I hope you are doing well. I hav Eden questions before I answer your questions. What type of corrosion logs you have ? Multifinger caliper or electro magnetic logs. Are you only have concerns about tubing or casing as well? What type of corrosion you have in the well. Is it only pitting or pipe deformed or other mechanical failure too?
how much of your pipe % is corroded in terms of grading as per Industry  practice. 

what are the fluid compositions for injection or produced fluid this is very important to evaluate risk for corrosion.
do you have he's or co2? 

what is metallurgy of tubulars? Is it chrome or is it L80? 

sweet or sour production? 

you have multiple logs (2) logs, you can plot data side by side for viewer and thin remaining wall thickness data in time lapse format from LAS files and use statistical  approach to forecast trend. 

Remember all 'em logs have certain percentage of accuracy and error too.

the best log is caliper which is more accurate.

a rule of thumb every two years are recommends to run corrosion logs if you see any progress in the corrosion as time lapse ?
if fluid is more corrosive than I advise run for every year?
I hope I have covered all aspects of the question 

Kishore maheshwari 
kishoremaheshwari@outlook.com
calgary Canada 

Hello Kishore,

Thank you for taking the time to respond.

I believe the sense of my query is different from what I infer to be your line of thinking.
The question is not about processing a typical caliper log or a magnetic log and determining the % of corrosion, the grading of the pipes, which pipe is most corroded, and if there is pitting, corrosion or scale. We have all this information from the industry standard caliper/magnetic log report.

The question is about forecasting future corrosion based on two or more logs (of the same type) ran in the same well at different times. There are several challenges involved with this, and I am asking about the industry-wide accepted practices for issues such as:
- How should tool errors be accounted for when different tools (same type) are used at a distance of years.
- How is metal loss progress calculated for each depth step based on the above two logs, given that log depths do not usually correspond (line tension, logging speed, etc.).
- What is the generally accepted minimum log depth-step (of the LAS file) for such analysis.
- How is future metal loss progress forecasted based on such information.

Kind regards

------------------------------
Enis Aliko
Wellynx
Italy
------------------------------

Original Message:
Sent: 10-26-2022 09:25 AM
From: Kishore Maheshwari
Subject: Tubular corrosion evaluation

Hi Enis,
I hope you are doing well. I hav Eden questions before I answer your questions. What type of corrosion logs you have ? Multifinger caliper or electro magnetic logs. Are you only have concerns about tubing or casing as well? What type of corrosion you have in the well. Is it only pitting or pipe deformed or other mechanical failure too?
how much of your pipe % is corroded in terms of grading as per Industry  practice. 

what are the fluid compositions for injection or produced fluid this is very important to evaluate risk for corrosion.
do you have he's or co2? 

what is metallurgy of tubulars? Is it chrome or is it L80? 

sweet or sour production? 

you have multiple logs (2) logs, you can plot data side by side for viewer and thin remaining wall thickness data in time lapse format from LAS files and use statistical  approach to forecast trend. 

Remember all 'em logs have certain percentage of accuracy and error too.

the best log is caliper which is more accurate.

a rule of thumb every two years are recommends to run corrosion logs if you see any progress in the corrosion as time lapse ?
if fluid is more corrosive than I advise run for every year?
I hope I have covered all aspects of the question 

Kishore maheshwari
kishoremaheshwari@outlook.com
calgary Canada 

I understand what you are getting at. I don't believe there is any industry
standard for downhole casing, other than a conversion of metal loss in mpy
(mils per year) and assumption of a linear progression. If not, then now is
a good time for the industry to tackle this effort.



I have seen data that had been recorded in the 1950's and 60's that showed
a specific instance of non-linear corrosion progress. Pipe that was 9Cr-1Mo
would in the presence of H2S corrode until there was a coating of Chrome
Oxide, and then the corrosion rate would slow significantly and even become
zero. I am sure there are plenty of other examples of this. Of course,
when the coating was disturbed (for example running wireline logs) then the
corrosion would begin again concentrated in the areas where the coating was
disturbed.



I would think the two best sources to investigate for current models are:

1. The pipeline API standards, and
2. CRA manufacturers



Sorry I could not help more.



Regards

Olli Coker

Manager

Diamond C Enterprises LLC

(former ConocoPhillips and Altus Well Experts)

832-330-5066

OlliC3@gmail.com


Original Message:
Sent: 10/28/2022 4:55:00 AM
From: Enis Aliko
Subject: RE: Tubular corrosion evaluation

Hello Kishore,

Thank you for taking the time to respond.

I believe the sense of my query is different from what I infer to be your line of thinking.
The question is not about processing a typical caliper log or a magnetic log and determining the % of corrosion, the grading of the pipes, which pipe is most corroded, and if there is pitting, corrosion or scale. We have all this information from the industry standard caliper/magnetic log report.

The question is about forecasting future corrosion based on two or more logs (of the same type) ran in the same well at different times. There are several challenges involved with this, and I am asking about the industry-wide accepted practices for issues such as:
- How should tool errors be accounted for when different tools (same type) are used at a distance of years.
- How is metal loss progress calculated for each depth step based on the above two logs, given that log depths do not usually correspond (line tension, logging speed, etc.).
- What is the generally accepted minimum log depth-step (of the LAS file) for such analysis.
- How is future metal loss progress forecasted based on such information.

Kind regards

------------------------------
Enis Aliko
Wellynx
Italy
------------------------------

I agree with OLLI,
LAS files should be from 5 to 30 mm step rate for corrosion logs. There is no such formal industry practice for forecasting corrosion. Generally speaking each operator has its own workflow to do this task. There could be 10-12% error in electro magnetic logs. If you plot two logs side by side find out linear change in wall thickness data. Most of the integrity guys extrapolate that curve linearly by assuming everything is same like coating, fluid compositions.
One important thing I would like to raise attention that your MAASP value will
Change with reduction in wall thickness. So you have reestimate MAASP value with new metal loss percentage.
Caliper logs have now accuracy in contrast to em logs.

Kishore Maheshwari


Original Message:
Sent: 10/28/2022 10:27:00 AM
From: Oliver Coker
Subject: RE: Tubular corrosion evaluation

I understand what you are getting at. I don't believe there is any industry
standard for downhole casing, other than a conversion of metal loss in mpy
(mils per year) and assumption of a linear progression. If not, then now is
a good time for the industry to tackle this effort.



I have seen data that had been recorded in the 1950's and 60's that showed
a specific instance of non-linear corrosion progress. Pipe that was 9Cr-1Mo
would in the presence of H2S corrode until there was a coating of Chrome
Oxide, and then the corrosion rate would slow significantly and even become
zero. I am sure there are plenty of other examples of this. Of course,
when the coating was disturbed (for example running wireline logs) then the
corrosion would begin again concentrated in the areas where the coating was
disturbed.



I would think the two best sources to investigate for current models are:

1. The pipeline API standards, and
2. CRA manufacturers



Sorry I could not help more.



Regards

Olli Coker

Manager

Diamond C Enterprises LLC

(former ConocoPhillips and Altus Well Experts)

832-330-5066

OlliC3@gmail.com



Original Message:
Sent: 10/28/2022 4:55:00 AM
From: Enis Aliko
Subject: RE: Tubular corrosion evaluation

Hello Kishore,

Thank you for taking the time to respond.

I believe the sense of my query is different from what I infer to be your line of thinking.
The question is not about processing a typical caliper log or a magnetic log and determining the % of corrosion, the grading of the pipes, which pipe is most corroded, and if there is pitting, corrosion or scale. We have all this information from the industry standard caliper/magnetic log report.

The question is about forecasting future corrosion based on two or more logs (of the same type) ran in the same well at different times. There are several challenges involved with this, and I am asking about the industry-wide accepted practices for issues such as:
- How should tool errors be accounted for when different tools (same type) are used at a distance of years.
- How is metal loss progress calculated for each depth step based on the above two logs, given that log depths do not usually correspond (line tension, logging speed, etc.).
- What is the generally accepted minimum log depth-step (of the LAS file) for such analysis.
- How is future metal loss progress forecasted based on such information.

Kind regards

------------------------------
Enis Aliko
Wellynx
Italy
------------------------------