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Pipeline damage/failure root cause

Pipeline damage/failure root cause

Pipeline damage/failure root cause

(OP)
Hello everyone,

I work in an upstream oil and gas site in Egypt.
Recently, 18 months ago, we introduced into service a new 2 phase crude oil 12" subsea carbon steel pipeline run from a gathering platform of nearly 40 meter water depth to the onshore oil terminal process.
The pipeline designed to the DNV-F101-OS offshore standard and the subsea installation carried out through the S lay barge.
Unfortunately, Three weeks ago, we have an oil spell over the line, we got forced with unplanned shutdown and switch over the production stream to another 3phase 20" pipeline.

The divers did finally catch four leakage points / ruptures observed sequentially after repetitive hydrotests.
The ruptures located at different distances apart from each others, the initial investigation showed nearly a same configuration for the rupture defects @ weld HAZ area.
The welding process at the barge got strictly controlled through three fully supervised welding inspectors that followed the DNV code instructions, hence we fairly exclude a sharp welding defect that emerges repeatidely nearly at the same locations relative to the girth welds, both axially (@the HAZ) and circumferentially (nearly the same O'clock side)

By the way, after completing the successful hydrotest and geometry pig, the pipeline got preserved about 6 months before introducing into operation with a doubt in the efficiency and control of the presevation process.

On the other hand, few months ago, the onshore section connected to this subsea pipeline has suffered a lateral movement of about 1.5 meter over the resting concrete supports that caused a damage observed for the pig trap supports.
We,here, guess that operation surges might cause the damage shown at the onshore section and hidden at the offshore subsea one. I guess that the heavy concrete coating the subsea section preclude its lateral movement, and initiate a huge fatigue stresses that released in a rupture form.

At the same time, the line convey two phase crude of %70 water cut with a relatively low flow speed, and the corrosion of the internal surface might accelerate heavily but how we could believe that corrosion leads quickly to this catastrophic failure.

We are planning to call an experienced third party to present an engineering failure root cause analysis to stand on the most likely failure reason and help support Safe future operation.

Also, we have to garantee all the following conditions together:
- Assure the pipeline integrity via confirming no other severe cracks left in the line after doing pigging using the compo tethered solution including both crack detection (TOFD technique) and corrosion detection technique.
- Confirm the failure root cause analysis to assure future Safe and reliable operation without the repeat of this catastrophic failure.

Finally, I would be grateful if someone advise the potential failure root causes that might be relevant to this kind of catastrophic failure.

RE: Pipeline damage/failure root cause

First two questions:

1. Is there corrosion inhibitor injection into the line?
2. What work was done to select a welding consumable chemical composition?

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

RE: Pipeline damage/failure root cause

I would also suspect corrosion, especially if the leaks are remote to the displacements.

Whats the chemical composition, salt content, of the oils, gases, water and temperature?

RE: Pipeline damage/failure root cause

With all the data you have, you can run an engineering critical assessment (ECA) of the failure to identify the most likely cause(s) leading to this early failure.
Got this run fir a couple of pipeline failures onshore and offshore, great tool to provide evidence for insurance and law case.
Please only use ECA specialists, otherwise you may end up with bad surprise. Garbage in, garbage out!

RE: Pipeline damage/failure root cause

Mahmoud,
Lots of questions arises after the physical evidence of failures you have listed.
1. Leak at HAZ - Obviously, those are the highest stress point to cause the crack and hence a leak. Investigate the following:
a. Correctness of WPS including PWHT.
b. The technique of application of internal coating was after the welding. Coating failure can lead to stress-corrosion failure.
c. If a free-spanning occurred? Usually, caused by scouring of the sea bed the pipeline rest on that lead to high bending stresses.

2. How was the 6 month preservation done after the hydrotest? Dryout process, purging/interting etc.

3. The 1.5 meter onshore displacement, indicates presence of slugs. Obviously appears that the onshore risers are not modelled/designed correctly that the loads are getting transferred to onshore supports including the pig receiver.

Two-phase flow regimes in subsea pipelines are complex and designers uses different mathematical models to best guess it but again depends on many parameters like flow rate, pipe diameter, hydrodynamic behavior at horizontal and vertical sections. Do you have a slug catcher?

Many offshore pipeline failures are attributed to Flow Induced Vibration (FIV) by multiphase flow that leads to fatigue failures.

Nonetheless, the HAZ seems to be the weakest points (high stress points) that has led to cracks and consequent leaks. It could be the summation of all or either of residual stresses after welding, stress corrosion and fatigue.

GDD
Canada

RE: Pipeline damage/failure root cause

Maybe I missed something : Why isn't the first question "Is this sour service "?

RE: Pipeline damage/failure root cause

Supposedly H2S content would be included in the response to this question.
"Whats the chemical composition, ..."

RE: Pipeline damage/failure root cause

What position is the leak in circumference?

HAZ gets some odd effects. If there is a high acid no in the Crude you can get preferential corrosion.

Was the pipeline internally coated?

Are you ever going to bother to log back in to see the replies (last login on 21st Aug)?

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

RE: Pipeline damage/failure root cause

(OP)
Execuse me, every one, nearly all times I login, the website, i get server error/access denied.
Thanks for all your invaluable technical discussions.
Iam going to reply to all.

RE: Pipeline damage/failure root cause

(OP)
First, Mr. SJones
- Yes, there was a tight corrosion inhibitor management program during the pipeline operation.
- The Welding process WPS was qualified through approved PQR record including the qualification of weld consumable chemical composition.

RE: Pipeline damage/failure root cause

If you are having trouble logging in it may be due to the time difference - I think the server shuts down for maintenance operations during the nightime in North America, so mid-day in Egypt is probably around that same time. It's a guess, but I have gotten that same message late at night in North America.

RE: Pipeline damage/failure root cause

(OP)
Reply to 1503-44 (Petroleum)

Regarding your question, i still wait a response from my colleague in Chemical and corrosion department.
But these the information I get till now.
The produced heavy crude has %70 WC.
The gas phase nearly separated at the production platform upstream the pipeline and the transferred crude has very little gas content.
The salt has 8603 P.T.B.
The temperature is around 40°C.
Attached is the formation water analysis report.

RE: Pipeline damage/failure root cause

(OP)
Mr. BenMacier
Thanks for your advice. We have already called for a threat assessment via a third party.
But we hope thatvthe third party experts are well aware with ECA procedure. I think the British standard 7910 presents a guide for crack management program.

RE: Pipeline damage/failure root cause

(OP)
Reply to Mr. GD2 (Mechanical

1. Leak at HAZ - Obviously, those are the highest stress point to cause the crack and hence a leak. Investigate the following:
a. Correctness of WPS including PWHT.
- The WPS was tightly reviewed and the PWHT was not a requirement as the this carbon steel line pipe grade;API5LX53 (P no. 1 & grade no. 1) has its heaviest wall thickness of (0.6") that doesn't exceed the required threshold for such PWHT.
b. The technique of application of internal coating was after the welding. Coating failure can lead to stress-corrosion failure.
- No internal coat was applied neither for the line pipe nor for the weld joint, as it wasn't stated in the pipeline design specs sheet.
c. If a free-spanning occurred? Usually, caused by scouring of the sea bed the pipeline rest on that lead to high bending stresses.
- No free spanning observed as informed by the divers.
2. How was the 6 month preservation done after the hydrotest? Dryout process, purging/interting etc.
- I think it was well applied through a properly designed preservation programin at the first time after hydrotest, but they probably displaced the preserved media while applying the Geometry pig run, i could not assure the integrity of such 2nd process, may it was not applied at all.


3. The 1.5 meter onshore displacement, indicates presence of slugs. Obviously appears that the onshore risers are not modelled/designed correctly that the loads are getting transferred to onshore supports including the pig receiver.

Shurely, We should think about the slug operation, but anyway, the onshore pig trap is the old one that installed nearly 40 years ago and already left without replacement as it was seen in a fair condition.

- There is no slug catcher, as the associated gas phase nearly separated at the production platform upstream the pipeline and the transferred crude has very little gas content.

Finally, I highly appreciate your invaluable discussion. Thanks alot 👍

RE: Pipeline damage/failure root cause

(OP)
Reply to Mr. Black Smith 37 (material) and 1503-44 (Petroleum).

The produced crude is not sour one, the H2S content doesn't exceed 200ppm.
On the other hand the pipeline design specs had referencd the NACE 0175 for any future sour service operation.

RE: Pipeline damage/failure root cause

Depending on total pressure , 200 ppm H2S can cause sulfide SCC of hard weld HAZ; that would be the first place I looked.

RE: Pipeline damage/failure root cause

Did the "corrosion inhibitor management" include assessment of the propensity for the inhibitor to cause preferential weld corrosion? The weld metal composition is also an interlinked parameter.

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

RE: Pipeline damage/failure root cause

Did any else look at that water report?

Looks pretty corrosive stuff to me.
Was there any corrosion inhibitor?
Some wells quite low pH.

HAZ gets some strange effects at times which are difficult to predict.

I suspect you will find lots more corrosion.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

RE: Pipeline damage/failure root cause

So, we have given some potential failure causes, but there is no way that we can advise on the root cause. That is a specialist process that lends itself even less than the failure cause to crowd sourcing on an internet forum. Let us know what failure cause is finally ascribed once a proper failure analysis has been performed.

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

RE: Pipeline damage/failure root cause

(OP)
Reply to Mr. LittleInch (petroleum):
Also: If you get a response it's polite to respond to it.

- Here I present my apology to all esteemed participants repeating my previous status:
Execuse me, every one, nearly all times I login, the website, i get server error/access denied.
Thanks for all your invaluable technical discussions.
Iam going to reply to all.

RE: Pipeline damage/failure root cause

(OP)
Reply to Mr. blacksmith37 (Materials):
Depending on total pressure , 200 ppm H2S can cause sulfide SCC of hard weld HAZ; that would be the first place I looked.

-From this point of view, I wouldn't think in the HAZ SCC, as the pipeline operating pressure doesn't exceed the 6 or 7 bar of the 40 bar pipeline design pressure, hence the generating hoop stress is so low to promote the SCC.
It value doesn't touch even the %30 of the SMYS.

RE: Pipeline damage/failure root cause

(OP)
Reply to Mr. SJones (Petroleum):

Did the "corrosion inhibitor management" include assessment of the propensity for the inhibitor to cause preferential weld corrosion? The weld metal composition is also an interlinked parameter.

-At the beginning, i got suspect in the selective girth weld corrosion as the defects repeated in the same locations (HAZ) relative to the girth welds, but again how did they failed nearly at the same time and looks like ruptures not corrosion.
Anyway way, I think the corrosion inhibitor management has not been planned to target such specific defect.
Also, there are other crude oil pipelines that interconnect the wellhead platforms to the production platform transferring the same crude, have been operating for nearly 40 years, since day one operation, and were not reported to suffer specifically from such kind of defects.

RE: Pipeline damage/failure root cause

@Mahmoud Khalaf - regarding stress at the welds: don't forget the weld zone will have residual stress irrespective of hoop stress. Typically, the stress is taken to approximate the yield stress of the material.

Unless each WHP is supplying identical crude, the fluid in the export pipeline could be considerably different after processing and commingling.

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

RE: Pipeline damage/failure root cause

(OP)
@SJones
The effect of HAZ residual stress would promote cracking when welding conditions support this.
But our case, we have mild steel grade X52 of very low carbon content and small wall thickness of 9.5 mm sch.40 pipes at all leakage/rupture locations. Those with accompanied qualified WPS insure slow cooling rate with slow heat dissipation process that doesn't require PWHT.

What do you mean with:
Typically, the stress is taken to approximate the yield stress of the material.

Thanks for your cooperation.

RE: Pipeline damage/failure root cause

(OP)
@Mr. Steve
Thanks for attaching such relevant and important technical paper.
I will read it soon to pick such relevant issues.
Again, highly appreciate your cooperation.

RE: Pipeline damage/failure root cause


a lot of brine has associated with biological growth, how is that being controlled

RE: Pipeline damage/failure root cause

Mahmoud Khalaf,
H2S PPM level don't decide on requirement of NACE material. The main criteria that decides NACE material usage are:
1. Partial pressure of H2S. Is it more than 0.05 psia (0.3 kPa)?
2. In situ acidity PH value of the water phase.
3. Chlorine ion concentration in the water phase.
4. Exposure temperature, time
5. Total tensile load (applied and residual).

You had submitted couple of information for above.
The EPC company must have done a due diligence and evaluated the process conditions while designing the pipeline but you never know. Knowing the H2S partial pressure might probably give a pointer to whether NACE compliance was required.



GDD
Canada

RE: Pipeline damage/failure root cause

(OP)
@GDD
Thanks alot 👍 for your thorough engineering comments.

I did suppose that the pipeline design had referencd NACE compliance as all site precess offshore and onshore pressure vessels were actually designed to comply with NACE requirements for sour service.
But, now, I don't suppose that compliance considered in the pipeline design neither for this new line nor for the old one.

I think that EPC company ( by the way, they are two the first for engineering and procurement and the second for construction) wouldn't have considered this compliance even they would receive such required information/data.

The above is for organizational point of view while from technical point of view, i would present some inquiries:

The five requirements you have previously introduced to force such compliance, they have to be included together or just one requirement could force such compliance? I think they have to be included all together.(I just guess, otherwise, i have to check the standard)

Anyway, I will search for other available information you have mentioned above.

Thanks again.



RE: Pipeline damage/failure root cause

(OP)
@Mr. Steve

I have quickly browsed the relevant technical paper you have recently attended but shurely, it needs much time to study and well recognize it's invaluable content.

Really it focuses on a critical parameter (residual stress effects) that should be profoundly considered and controlled during structural project engineering and construction phase.
We agree on the adverse effect of residual stress on the weld joints integrity and it needs measurements to stand on its approximated values as the study states the higher residual stress magnitudes that could approach the material yield strength itself.

But, again, I would inquire that our case might be relatively different when compared with the weld joints mentioned in the study for the following reasons:

- in our case, the pipeline has less wallthickness (9.5 mm) than both joints mentioned in the study (19 mmm for the 16" joint and 22 mm for the 20" joint), this will reflect less material cross section and volume that leads to slower cooling rate and heat dissipation as well, as you know the heat conductivity is at its highest rate through the metal cross section. This mandates PWHT requirements for higher wallthickness weldments to metigate the adverse effects of residual stresses.

- Also, the pipeline material is API 5LX52 which is less in its yield and tensile strength values compared to both the two weld joints X65 and X70 mentioned in the study, this leads to easier weldability for X52 pipe and less residual stress relevant to its less carbon content.

Highly appreciate your cooperation.

RE: Pipeline damage/failure root cause

I have performed a number of audits of X52 pipe tensile properties and over 80% met or exceeed X60 tensile properties. I remember a similar failure with an underwater line in sour service where the pipe was specified as X42 but tensile properties were close to meeting X60 and CE was not controlled. I always wrote specs controlling chemistry of X42 and X52 for pipe in sour service.

RE: Pipeline damage/failure root cause

(OP)
@ weldstan (material)

Firstly, thanks for your comment.
I think you get broaden the uncertainty domain of the parameters relevant to this pipeline failure case.

But, as stated in your audit results which concludes that a major percentage of the mill produced pipes for defined steel grades are actually more relevant to a higher strength grade, then if your results would be presented in a tight study parameters that statistically valid, in my opinion, this would introduce some inquiries:

- The QC level for material specification should be reviewed in the steel mill to insure accurate and approved acceptance criteria regarding this issue, as this would introduce adverse effects in relation to residual stress and carbon content control for the welding joints.

- Based on your results, and if many literaturally published studies would well state and approve such results, it might be introduced as an ASME/DNV code case that might recommend PWHT as a conservative procedure to mitigate such adverse effects of residual stresses and uncontrolled carbon content for defined steel grades, at least, for such critical/costly industries.

Unfortunately the concequences in subsea pipeline failure is unaffordable as just one uncontrolled welding joint or unconsidered process parameter could initiate the failure even in one location, this usually forces costly production down time and costly repair procedure.

RE: Pipeline damage/failure root cause

The five requirements you have previously introduced to force such compliance, they have to be included together or just one requirement could force such compliance? I think they have to be included all together.(I just guess, otherwise, i have to check the standard).

Mahmoud,
All the factors I mentioned contribute to an environment for the diffusion of atomic hydrogen into the metal leading to SCC/SSC.

One thing I am wondering is why the cracks are all at 0 O'Clock position.

GDD
Canada

RE: Pipeline damage/failure root cause

Steel mills are out to make the greatest profit and have increasingly made steels marked with multiple specs and grades thereof. Because steels are purchased from numerous mills in numerous countries with differing steel making philosophies, it is imperative that the end user understand just what is required for the service conditions and generate controling specifications that refflect that service. Unfortunately this is often not so.

RE: Pipeline damage/failure root cause

(OP)
@ GDD

One thing I am wondering is why the cracks are all at 0 O'Clock position.

No. I didn't mention that, refer to the main thread, I mentioned the same O'Clock not 0 o'Clock position.

Anyway, the divers vedios reported the 6 O'Clock position; definitely, three locations at 6 O'Clock and the fourth location at nearly 4 O'Clock.

Here i think this might strengthen your guess of SCC/SSC at pipeline bottom surface where microbiological deposites settle?

RE: Pipeline damage/failure root cause

Mahmoud,
Another question that should have been asked before is was the API5LX52 pipes PSL1 or PSL2? By what you said so far I would guess it is PSL1.

GDD
Canada

RE: Pipeline damage/failure root cause

(OP)
@GDD
The line pipe spec. as requested by the Engineering company was PLS2.
Iam trying to find the MTR of the purchased line pipe received from steel mill.

Note:
In the attachment, the bottom green mark/arrow refer to No Sour as supplementary requirements of the line pipe specification sheet!!

update: iam trying to attach the document.

RE: Pipeline damage/failure root cause

Quote (Mahmoud Khalaf)

Also, the pipeline material is API 5LX52 which is less in its yield and tensile strength values compared to both the two weld joints X65 and X70 mentioned in the study, this leads to easier weldability for X52 pipe and less residual stress relevant to its less carbon content

For residual stress estimation in your case, why not complete a calculation using the formula in clause 11 of the UK HSE report? You will note that has no dependency on pipe grade, carbon equivalent etc.

https://res.cloudinary.com/engineering-com/image/upload/v1630578636/tips/Residual_Stress_ip0y7s.pdf

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

RE: Pipeline damage/failure root cause

Corrosion at the bottom of the pipe is quite telling, especially with your statement "the pipeline got preserved about 6 months before introducing into operation with a doubt in the efficiency and control of the preservation process."

Getting bugs in the system can just eat your pipe and with an internal weld bead you may have just developed a little pool of microbes in this area and had them leach acid onto your HAZ.

Once you get a corrosion hole going it doesn't take much of your slow moving oil in water mix to get accelerated corrosion if you were down to 2-3mm by that time. You don't say what, if any, corrosion inhibitor you're using? Or maybe I missed it?

Process plants have had to be re-piped in the past due to hydrotest water sitting in them for 6 months before operation.

Your other pipelines may have started off transporting much more oil than water and hence tend to get protected a bit by the oil. once you go to 70% W/C you're in a different land.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

RE: Pipeline damage/failure root cause

(OP)
@Steve
The TWI study target the normalized residual stress readings (residual/yield - Y axis) versus a specific location relative to the sample thickness (normalized thickness-X axis).

This is different issue that I would present.
In metallurgy science,the below is a rule:
Increasing the carbon content (%carbon, %Mn, Cr, etc..) will increase the yield and tensile strength values and decrease ductility.
This means also harder metal forming process (weldability in our case)and increase the tendency to generate more residual stresses regardless its type (hoop or axial, tensile or compressive, etc..).

Therefore the majority of the high strength alloy steel families mandate PWHT, regardless its thickness, as it has relatively higher carbon content induced by the added alloying elements (Cr, V, Mo,..) and when welded generate higher residual stress that mandates PWHT to soften the harder produced microstructures,

RE: Pipeline damage/failure root cause

@MK
You may want to talk to a welding engineer about some of those statements. Irrespective of composition, the simple fact of having a liquid metal pool freeze between two very large members is going to generate some residual stress somewhere. Whether the stress was sufficient to assist mechanical cracking, or stress corrosion cracking, only your failure analysis will tell. The “repetitive hydro testing” may also have served to propagate defects to failure point.

Steve Jones
Corrosion Management Consultant

www.linkedin.com/in/drstevejones

All answers are personal opinions only and are in no way connected with any employer.

RE: Pipeline damage/failure root cause

(OP)
In the above main thread, I did mention the below status:

On the other hand, few months ago, the onshore section connected to this subsea pipeline has suffered a lateral movement of about 1.5 meter over the resting concrete supports that caused damage observed for the old pig trap supports.
We,here, guess that operation surges might also cause the damage observed at the offshore subsea section. I guess that the heavy concrete coating the subsea section preclude its lateral movement, and initiate a huge fatigue stresses that released in a rupture form.

The question is; to What certainly level, we could suppose that damage relevant to fatigue cracks iniated due lateral loads induced by operation surges could be a root cause? I know that it needs deep investigation but might someone has a relevant experience do guess?

Does the fatigue failure occur in many locations distributed along the pipeline and probably in relatively same time or just one fatigue rupture could cause full relief to the operation surges induced stresses? If it is nearly fatigue, why did it repeat at many locations nearly distributed within 500 meters along the pipeline?

RE: Pipeline damage/failure root cause

Mahmoud,
It's hard to believe that the pipeline will have a fatigue failure only after a run of 18 months and that too at a pressure of 6/7 bar over a design pressure of 40 bar at 40 degree C.
You said that you had some operating surges. What exactly is that? Or operating upsets?
Do you have data on cyclic Loading time histogram on pressure and temperature cycles? 15 -20% on pressure variations of the design pressure shouldn't be a contributor to fatigue failure. I wouldn't also think that you had a lot of temperature variations.
I still suspect that your 6 months preservation played a big role in initiating corrosion. All failures in the HAZ indicates that Non-PWHT of the welds have contributed to the stress level.
Did you find the MTR for the pipes? PSL2 pipes are primarily used for sour service. It requires controlled welding.
Last but not the least, did you check if the onshore plant saw frequent process loading variations. If there was slugs coming in the flow, with no slug catcher, they should see it.

You also said that there was a crack at 4 O’lock position. What is this location’s elevation compared to other locations? Is this the lowest point in the pipeline profile?

GDD
Canada

RE: Pipeline damage/failure root cause

(OP)
The 4 O'Clock rupture is the nearest one to shore line so nearly it has the highest elevation (-11 m)relative to the upstream remaining three ruptures as the line runs from -40 @ riser seabed-touchpoint to the downstream onshore terminal of a relatively sea level elevation.

Another issue that lets me doubt about fatigue is the rupture morghology which looks like fish🐟 eye, the most defect morghology relates to fatigue rupture. Rupture image is attached.

Again if the doubtful presevation procedure had greatly been a powerful factor in the failure initiation process, so, in my opinion, it should be logic that the failure morghology appears like Corrosion of uneven shape dimensions rather than these observed sharp edge appearing rupture located everytime at HAZ?




RE: Pipeline damage/failure root cause

(OP)
Conversely, another important information that disrupt my guess in fatigue failure is that the diver points in a diving vedio to a confirmed hole beside one of the ruptures with dimensions of 2.5 cm length in 1 cm width!

Video is attached; the hole is clearly seen at the second 71 (01 minute:11 second)

RE: Pipeline damage/failure root cause

In galvanic corrosion of carbon steel we often see the weld acting as the anode and will have substantially higher corrosion rates than the surrounding metal. If galvanic corrosion is occuring internally, the entire weld bead may be wasted away but the cross-section is thinnest at the toe which is why the corrosion appears localized in that area. Given more time, the cap would corrode away as well.

Here is an example of a weld bead hanging from a pipe due to galvanic corrosion. It corroded through at the toes on each side of the weld and the crown fell off.

RE: Pipeline damage/failure root cause

Mahmoud,
Can you send us the process stream condition when it enters the pipeline after the offshore separation plant with the H2S partial pressure?

I will rule out fatigue failure. Reason: Even if there is one process upset cycle a day, 540(30/month x18 months) cycles is not enough for a fatigue rupture given that it is operating only at 18% of the design pressure.

GDD
Canada

RE: Pipeline damage/failure root cause

(OP)
Come back,
We have informed recently via verbal confirmations, that many times when instrumentation guys do their routine PM at the production platform, they reported verbally a non conformance events, they found the level control loop of the production separator upstream the pipeline routinely switched override!, and even the automatic shutdown valve and pressure switch high (PSH) connected to the pipeline found overrided too!!

When they were asked, the process guys replied that due to the upstream process disturbance(wellhead flow regime) we were forced to do so, otherwise a complete shutdown would have been initiated so much,even daily!.

Regardless this attitude and its relevant refused justification, we expect that due to this reported miss level control, considerable amounts of gas surges would have been introduced into the liquid phase inside the pipeline and might initiate a slug flow regime. when we do a relationship between this event and the confirmed pipeline snaky movement seen for about three hours and reported four months ago before the accident, I would guess the displacement overstress ( huge bending stresses) that might contribute to this disastrous failure.

I do, here, differentiate between irrelevant fatigue stress and the displacement overstress we talk about.

I would inquire, does this guess seem true ?

RE: Pipeline damage/failure root cause

Mahmoud,
It appears that slugs are flowing from the wells making the separator units unstable. This is one of the major challenges in operating offshore facilities. One of the things Operations have done is override the separators controls. If you ask around, you might also find load and vibration issues with the gas compressors that flares the gas.

Nevertheless, the root cause of these problems - the slug flow - must be smoothened and controlled. Operation is right, if they didn't override, it should been more trips and shutdowns.

Several approaches are adopted to get way with this this kind of problem. Onshore slug catcher is one which you don't currently have. Sometimes, they make the first stage separator bigger or by adapting the separators to receive the slugs.

With regard to the subsea pipeline, it must have seen intermittent liquid plugs and even stalled flow. This on-off flow patter and the energy the liquid plugs dissipated must be the cause for the pipeline rupture and the onshore damage/displacements at the pig receivers.

In my perspective, analyzing for fatigue failure is not going to remove the root cause of the failure. It will come back again. The issue must be looked from an organization point of view with operations, process, inspection, engineering groups and a corrective action o smoothen the slugs must be planned.

Slug flows are common, it's a challenge but there are also means and ways to control it. Overriding controls and not taming it, is not a solution.

GDD
Canada

RE: Pipeline damage/failure root cause

(OP)
GDD

Thanks alot for your long breath discussion and valuable comments that i would highly appreciate.
I would ask about your advice regarding such below issues.

Till we, based on an organisational scale investigation, catch the most likely failure root cause and although this is a hard mission due to socio-cultural issues, we should deal with the disturbed operation as new emerged challenge.
The wellhead flow regime might get new harsh flow characteristics that should be modelled in a different profile that differs from the old original one.

This new flow modelling has to be designed through special engineering organization and should conservatively suppose the relevant flow parameters in its extreme figures/values.
Concequently this wellhead flow model might force substational modification in the downstream precess onboard the production platform like upgrading the heritage pneumatic control system, resizing the separators, equip new system, etc..

But as we know this is a hard challenge and might require much funds that the concerned shareholders are not willing to pay, in such brown field, so the other alternative that could be studied, specially if it gets incidentally forced to switch the production stream back to 12" main oil line and after considering the economic impact of accompanied potential deffered production, is to keep gas lift operation either completely or partially outage and maximize the production dependency on ESP solution only, even with its relevant operation upset which might be less disturbant and more safe when compared with the exising slug flow regime that disturbed by uncontrolled gas surges mainly feeded by gas lift operation.

Mahmoud Khalaf
Asset integrity.

RE: Pipeline damage/failure root cause

Mahmoud,
I am not onto Downhole engineering.
What I see from your perspective is that management wants to fix the broken line ASAP and start production. You can't do much in doing a good engineering job right from downhole to re-engineering of the whole system. This kind of project will atleast take upto 3 years from approval to construction. You guys being in a tight spot and in operation, management is tracking how soon the line will be repaired and up and running again.
So my advise it, within your limited scope and responsibility, fix the line and bring it to the shape back. Let your engineering team work on the root cause issues, which I am sure will continue through tens of discussions and deliberations until a decision for corrective action plan is taken.

Not much help from engineering stand point but this is exactly what happens in an operating plant environment once the project is handed over to the operation and maintenance. And you are right- socio-cultural issues more than what needs to be planned and done.

GDD
Canada

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