Hi Basker. I will continue to engage with the lead author of the report and cc: you... let's see where that leads (most probably not very far). But still worth engaging...
Re: the original thread and the reliability of DHSV's for deep applications (ie. Deep-Set valves) I would also add that any specific application deserves a bit of extra work and sometimes specific engineering... valves strictly "off the shelf" may have a very stiff spring by default, for instance designed for operation at pressures close to 9,000psi. It is beneficial to consider the operating conditions specific to a project and potentially choose either the closest "off the shelf" valve available (avoiding unnecessary high CL pressure), or asking for the spring to be adjusted for a specific project (ie. just the CL pressure window you need). All this still with a view to limit the application of unnecessary high CL pressure when it can be avoided, to reduce stress on equipment (seals, ferrules) and hopefully improve reliability (again, using common sense / general principles, I don't have any data to prove that)
Original Message:
Sent: 08-16-2024 02:55 PM
From: Basker Murugappan
Subject: TRSSV reliability >3000ft
After reading the entire report, I have to admit that I was extremely confused with the conclusions.
This is an official report that was provided by the US government as guidance for underground storage facility wells and yet does not reflect the normal O&G practices and lesson learnt.
From my 1st mentor in Amoco for completion design: "Regardless, if the well is on land or offshore, If a well is self erupting, it requires a TRSSV. The well is like a tiger trying to break free of its cage, you job is to make sure the cage is strong enough and maintained at all times"
In fact there are now more instances, where a well is considered dead but come back to life in the middle of a workover.
So "dead wells"......are defined as?
Example are two separate incidents in two separate databases
Example 1
Example 2
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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
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Original Message:
Sent: 08-16-2024 10:35 AM
From: Pierre-edouard Vincent
Subject: TRSSV reliability >3000ft
Success... we should be able to engage directly with the lead author for follow-up and some gentle questions on some of the conclusions and how different offshore facilities can be from gas storage. This could actually make a nice joint webinar! (joint between P&ATS and WITS?)
@Matteo Loizzo if you like the idea I'll cc: you (and @Basker Murugappan) on my reply to Slawek?
Original Message:
Sent: 08-16-2024 09:37 AM
From: Matteo Loizzo
Subject: TRSSV reliability >3000ft
Hi Basker, Pierre-Edouard,
I fully concur with @Basker Murugappan that the report was written with a specific purpose. Since I know some of the authors I will bury the axe I normally grind and wear my silk gloves.
The report is written for an American audience, where DHSV's were "discovered" after the Aliso Canyon catastrophe. Knowing that the land is home to millions of active wells, and that I'm not sure the blowout would have been prevented by a DHSV (the gas may have left the production casing through deep-ish holes) a bit of push-back against the blanket adoption of these valves may be expected.
However, there are a couple of funny points that struck me during a very superficial read. First, API 581 is a beautiful standard, but hopelessly limited to plants. On surface. No wells. There is actually a strict disclaimer against this off-label use.
You can still get inspired by API 581 for a Reliability-Centered Maintenance analysis. Why not? But then you wonder how they can get a big enough statistical sample for their LOFI (e.g., failure frequency) estimation. Maybe producing wells in the US, but certainly no gas storage or subsea wells, for which we're two orders of magnitude short of experience.
Then there is Figure 2, where a likelihood of failure of 1 event per 1,000 well-year of operation, leading to a loss of $10 billion (a big Aliso Canyon or a small Macondo) would be deemed tolerable. That means you can go ahead. I don't know any operator who would tolerate a $10B loss per year on 1,000 producers.
A more appropriate criterion would be that if you can have a hydrocarbon (liquid or gas) leak rate of 10,000 tons per year, then you're into major accident territory. That means you need to install a DHSV. No ifs and buts. No probability excuses.
Is your well depleted, as most are? Then you can probably intervene and mitigate the already small leak. Do you really need to install a DHSV, i.e., two independent barriers? Nah, but you need a serious risk assessment to support this barrier strategy.
Mind that whereas it's easy to control liquid hydrocarbon leaks on land, methane goes straight into the atmosphere. And your reputation sinks.
Would I take this report as a basis of decision? Next question.
Gloves off. Grab the axe back.
Best regards,
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Matteo Loizzo
Well integrity consultant
matteo.loizzo@mac.com
Berlin, Germany
Original Message:
Sent: 08-16-2024 08:50 AM
From: Pierre-edouard Vincent
Subject: TRSSV reliability >3000ft
Hi @Basker Murugappan - I had a quick read through the Exec Summary part of the report
The applicability of SSSV depends on level of risk for given well:
• UGS wells with low risk (risk being defined as a product of likelihood of failure and
consequence of failure) would generally not benefit from an SSSV application. In fact,
the risk may be increased due to risks of more frequent and more complex SSSV-related
workover operations.
• For wells with moderate risks – driven by moderate or moderately high likelihood of
failure and combined with high to moderate consequence of failure – the application of
an SSSV can be seen as a cost-beneficial option at reducing risk when considering the
entirety of the net risk change.
• For UGS wells with inherently high risks, particularly when driven by high likelihood of
failure, the application of SSSVs may reduce risk but since SSSVs are a consequence
mitigation device, the reduction in risk does not treat such a well's initial, or inherent,
high likelihood of failure and thus the net risk change, while substantial in high
consequence cases, still may leave unacceptably high residual risks due to the
persistent likelihood of failure – and in fact the increased workover frequency for SSSV
reliability reasons could be seen as another reason to disfavor use of SSSV in such high
risk cases.
And in line with the other comment I made earlier today on another thread, while I would tend to agree with bullet points 1 and 2 above... I find the logic goes off the rails for the very end bullet point 3 (– and in fact the increased workover frequency for SSSV reliability reasons could be seen as another reason to disfavor use of SSSV in such high risk cases. ). Perhaps we practice/use a different definition of risks here...? If DHSV's do play a significant part in reducing the severity of potential incidents (mitigating consequences) then I don't see how in high risk wells there would be a case for arguing you're better off without DHSV's...
I've just gotten in touch with the author and cc:ed you Basker... hopefully we can get into some sort of a dialogue :) Let's see!
Cheers.