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Should we consider Sub Surface Safety Valves as a Barrier?
11 April 2016

Good day dear colleagues.

I am included into a team to write a company standard about our ”œBarrier Philosophy”. 

Some of us are stipulating that we can use a SCSSSV as a barrier (for workovers, well interventions etc.), once it was positively inflow tested with a zero leak rate. There are companies, but not all of them, whose policies or standards are not allowing that. 

Now, is there a good academic reason or technical explanation for allowing one or the other?

I would like to get your opinion on that subject. Also, if you can´t give me a good academic reason or technical explanation to go for one or the other, could you tell me how your company is dealing with this question and who that company would be?

Thank you very much for your time spent on reading this question already now!

Regards,

Heiko.

16 answer(s)
AndyPua
Drilling Consultant
PT Drilling Services
Total Posts: 62
Join Date: 15/09/14
Heiko, 
Most companies stick to 3 barriers nowadays : normally 2 mechanical barrier and one fluid barrier (brine or mud with higher density than the formation pressure). 
Mechanical barrier such as bridge plug or tubing plug and BPV will hold the kill fluid column to maintain the 3 barrier situation.
In wells that have two zones where one is lost zone and one is high pressure zone, then the SCSSV cannot hold the fluid column which allows the high pressure zone to kick in (if the other mechanical barrier fail). In that situation, SCSSV will not be a good barrier.
SCSSV also has tendency to jam open or unable to provide 100% seal against gas which is why it is never been considered a barrier in most companies. 
If it is a practical reason, a good risk assessment need to be performed and exemption is required before a SCSSV can be consider as a barrier.


greaneyt
Consultant
SPREADAssociates
Total Posts: 18
Join Date: 11/01/15
I must confess never having heard of V0, V1, V5, etc despite having some involvement recently in well integrity issues. I'm mostly involved in onshore activities where SSSVs are rarely required so perhap that's why. API well control guidelines for pressure testing (API Std 53 I think) refer to requiring pressure stabilising (i.e. dP/dT decreasing) rather than requiring a straight line. i've seen correspondence on this site referring to deep water BOP tests being non straight line and suggesting alternative criteria X psi / min or a Horner plot type analysis. Onshore a barrier test in the direction of flow is, in my experience, unusual. Offshore there is more scope to circulate the kill and choke lines or the Riser to a lighter fluid to create an underbalance. Gas testing, per V1-V3, is rare onshore too. I was a few years ago also involved with an onshore P and A project where occasionally we got a few, very few, bubbles through the abandonment plugs, occasionally even 3-4 psi which raised the unanswered question as to what was acceptable.
greaneyt
Consultant
SPREADAssociates
Total Posts: 18
Join Date: 11/01/15
I must confess never having heard of V0, V1, etc despite having some involvement recently in well integrity issues.

I'm mostly involved in onshore activities where SSSVs are rarely required so perhap that's why.



API well control guidelines for pressure testing (API Std 53 I think) refer to pressure stabilising (i.e. dP/dT decreasing) rather than requiring a straight line.

i've seen correspondence on this site referring to deep water BOP tests being non straight line and suggesting alternative criteria X psi / min or a Horner plot type analysis.

Onshore a barrier test in the direction of flow is, in my experience, unusual. Offshore there is more scope to circulate the kill & choke lines or the Riser to a lighter fluid to create an under slangs.

I was a few years ago involved with an onshore P&A project where occasionally we got a few, very few, bubbles through the abandonment plugs, occasionally even 3-4 psi which raised the unanswered question as to what was acceptable. 


KenHorne1
Multilateral Specialist
Multilateral Solutions
Total Posts: 36
Join Date: 30/09/13

Hi Steve.

My original question was ”œdoes a barrier have to be tested and meet V0” as it seems to me that the term V0 often gets used incorrectly and often totally in the wrong context.

Not so long ago I read a request for a V0 bridge plug to be used within a well with BTC casing, EUE tubing, and at best a V3 but probably V5 production packer.

So I guess Ifor, your comments are right that ”œa barrier does not have to be V0. The rating required is dependent on the well conditions”.




snas
Well Engineering Consultant and Instructor
Olango Consulting
Total Posts: 21
Join Date: 23/03/16
Ken,

I guess we have different standards that apply but for Norsok D10 to be classed as a well barrier, a barrier must have a zero leak rate with the test applied in the direction of flow both at low and at high pressure.

I guess if you were to apply ISO14310 to a BOP it would be a V5 (liquid test) although I have seen gas testing done on BOP's in certain applications. 

The low  and high pressure testing raises another issue, should an SSSV or a plug be tested at low pressures and at high pressures. we certainly have seen challenges with testing valves, especially flapper valves, at low pressures in the direction of flow.
KenHorne1
Multilateral Specialist
Multilateral Solutions
Total Posts: 36
Join Date: 30/09/13

Hi Steve.

So for clarification, are you saying that a BOP or an RTTS type packer or a wireline plug or bridge plug to be considered a ”œbarrier” must meet the criteria of  ISO 14310 qualification testing as below?

Testing a barrier at high and low pressures does not constitute V0.

 

V6 - Supplier/manufacturer defined

V5 - Liquid test

V4 - Liquid test + axial loads

V3 - Liquid test + axial loads + temperature cycling

V2 - Gas test + axial loads

V1 - Gas test + axial loads + temperature cycling

V0 - Gas test + axial loads + temperature cycling + zero bubbles leakage




snas
Well Engineering Consultant and Instructor
Olango Consulting
Total Posts: 21
Join Date: 23/03/16
A barrier must be V0
Consider a closed BOP as a barrier, you would not want it to be leaking, if something leaks it cannot be considered as a barrier. That is why we test barriers at high and low pressures.

The SSSV is generally not considered as a barrier because of its allowed leak rate. The stated leak rates allows pressure to be build up reasonably quickly between the SSSV and a closed valve at the surface.

As a reference the leak rate of 900 scft/hr may appear to be small, but it is equivalent to a 30 times the maximum rate the gas meter in your house delivers. A gas meter with a 22mm pipe delivers 30 scft/hr of gas to your house, not something you want to have as a leak.
IforJones
Completions Engineer
SPREADAssociates
Total Posts: 4
Join Date: 11/04/16
Ken,
From my experience the answer is no a barrier does not have to be V0. The rating required is dependent on the well conditions. However a lot of plugs used in well interventions are V0 rated (most extreme test conditions for validation as per ISO) which is why it is often used as a requirement to avoid confusion and prevent under-rated equipment being used.
Cheers
Ifor

IforJones
Completions Engineer
SPREADAssociates
Total Posts: 4
Join Date: 11/04/16
Heiko,
As previously mentioned this is a very common question and a discussion which I have been involved in on numerous occasions. 
I have been mainly working in the UK and unfortunately there is no simple answer as UK regulations are not descriptive, however the Well Life Cycle Integrity Guidelines from Oil & Gas UK maybe of use to you as a starting point. Based on their description, "these guidelines are relevant to all wells and well operations in the UK for the extraction of naturally occurring hydrocarbons. The guidelines describe what is believed to be good industry practice and refer to relevant legislation, standards and practices. The guidelines concentrate on ”œtypical” wells and ”œstandard” operations." In addition as previously mentioned Norsok standards are also good reference.
As a well operator you have to be able to demonstrate that risks are ALARP, and therefore from my experience (having worked for a number of different operators) the SSSV is not normally included as a barrier for standard operations.
The main reasons I have come across for not using the SSSV are:
- There needs to be a mechanical barrier above it to prevent it being opened by a dropped object (e.g. tool string). If you put a mechanical barrier in then you may as well set a plug and test it.
- You need a zero leak rate for a barrier and the API spec for a SSSV is not a zero leak rate.
- A SSSV may test as zero leak rate but then you have to be able to monitor it during an operation with  a positive differential across it. Because if the pressure differential across it goes negative it may open, in which case you need to retest it as you can not guarantee that it has re-seated with a zero leak rate.
However having said that I have come across operations where a SSSV has been used as one of the barriers, but this has normally been done after a very detailed risk assessment to demonstrate risks are ALARP, and it has been necessary due to well conditions.
Cheers
Ifor
KenHorne1
Multilateral Specialist
Multilateral Solutions
Total Posts: 36
Join Date: 30/09/13

Gents.

This is a very interesting discussion and I have a question regards the statement made by Chris in his response.  Does a barrier really have to be V0?

Regards

Ken........


whitehead
Senior Completions Engineer / Well Examiner
Engie
Total Posts: 13
Join Date: 06/06/11
Heico,
Your question is a very common one & you will already have had several conflicting answers as all operators do not view this issue the same way.
The current view in my company (and my own view also) is:
A two barrier policy will always be adhered to, dispensation will be allowed through a written dispensation route signed off by a competent authority (well examiner).
The two barriers must be independent of each other i.e a plug with kill fluid above is not a double barrier, but a monitored (100% of the time) fluid level may be construed as a barrier ONLY when the level can be constantly monitored and control of the level is possible if it changes either way (important condition)
A SCSSSV is not normally classified as a barrier, so two mechanical barriers should be the target.
From a practical perspective If an SCSSSV inflow tests with zero leakage, then this could conceivably be construed as a barrier, but only on the back of a rigorous risk assessment in context.
I work as a Global Completions & Intervention Well Examiner with Engie (formerly GDF Suez) in Aberdeen.







ahmedix
Consultant
SPREADAssociates
Total Posts: 9
Join Date: 26/09/13
A well control barrier is a V0 barrier for ND BOP's and NU the Tree or vice-versa. API-14A allows a certain amount of leak for a SSSV (flapper or ball). The Ball type was more reliable and it could be replaced prior to a work over and -nv tested. As a rule the SSSV is no longer a well control barrier. For work where the tree is still in place, it should be consider on case by case basis.
Heiko
Well Services Manager
Sasol Ltd
Total Posts: 5
Join Date: 11/04/16

Thank you very much Mike, Ruari and Chris,

For your answers, they were very helpful so far in having further thoughts.

Chris, thank you very much for the hint with the NORSOK D010! The NORSOK D010 is mentioning the DHSV (Down Hole Safety Valve) nine (9) times in the schematics, where it is part of the well barrier envelope:

-       Of which are four (4) for production or injection wells.

-       One (1) is showing a DHSV for pulling a BOP and landing a tree, with a mechanical plug set below (So how would you now inflow test the DHSV?) and a ”œdebris plug” set into the tubing hanger profile, preventing the concerns of Mike, that something drops on the DHSV and opens it (see Page 69 of NORSOK D010).

-       Three (3) times the DHSV is used for isolation purposes: rigging up wireline, CT-equipment or snubbing equipment above a surface tree (XT).

-       And the DHSV is mentioned once (1) for pumping into the well, if tree (XT) isolation tools are installed in the XT.

On page 162 the NORSOK D010 (definitions table for the well barrier elements) is than talking about the leak rates acceptable by the DHSV as indicated by you Ruari and Mike (you were very close with your top of the head figures Ruari):

a) 0,42 Sm3/min (25,5 Sm3/hr) (900 scf/hr) for gas;

b) 0,4 l/min (6,3 gal/hr) for liquid.

Is that not strange? I would not accept a leaking barrier.

I believe there is/are still not yet an academic or a technical sound answer(s) to go for one or the other direction, is there?

Thank you very much gents for your feedback and input so far!

Cheers,

Heiko.

harshmind
Drilling Adviser
SPREADAssociates
Total Posts: 3
Join Date: 14/11/15
Heiko,
If you have access to Norsok D-010, this is pretty much a de facto standard world-wide.  I suggest you scroll quickly through the document, stop at each well barrier schematic, see if it features a SCSSV in the table to the right of the schematic, make a note it if it does, and move to the next schematic.  You will quickly find in what circumstances the SCSSV can be regarded as either a primary or secondary barrier and it's probably not too many worker or well intervention activities once tools are into the completion.
RuariTruter
SPREADAssociates
Total Posts: 18
Join Date: 17/09/07

Heiko

It's not so much that they normally leak (Mike's usually correct assertion) but rather that they are not designed NOT to leak.  Can't quote the actual API spec but an SCSSSV, by design, can have an acceptable leak rate.  This is also reflected in the views of various regulatory bodies.  Off the top of my head it is 0.43 cubic meters / min of gas or 0.400 cubic meters/min of liquid.

So that's the technical reason to say no to their use as a barrier.

Having said that, I am sure certain brands are designed to be 'zero leak' and indeed some may be very reliable.  Additionally you can test one to your satisfaction. 

 As a first pass some companies are accepting a new, shop tested SCSSSV as a barrier for installation (No plug needed downhole in the tubing while putting your XT on).  Some take this further and accept a robustly test (Inflow tested?) SCSSSV to take a XT off. Not sure if you would find anyone accepting a leaking one.....

In all cases, this would be as a second barrier.  If this was your only barrier, it would depend on your assessment of the risk.  As Mike alludes to dropping toolstrings might be riskier than pulling a XT off with a well on static / low losses and plenty of brine on location.

Any barrier policy would have to make some form of table when it was acceptable and under what circumstances.  Cos sure as God made little apples, you say it can be used as a barrier, one of your company men will whip off a tree with a leaking SCSSSV saying 'but API accepts a leak"

I'm working as a Well Examiner at present

Cheers....Ruari


HartWell
Well Integrity Lead
HartWell
Total Posts: 5
Join Date: 07/01/16

There is a school of thought that says a SCSSSV should not be used as a barrier, but its mainly related to the fact that they will normally leak! So if you require a zero leak rate, then in my opinion its perfectly logical.

I am the well integrity authority, and I guess its up to me! You may have to think about if you want to specify something other than a zero leak rate. Also if the safety valve is the only barrier, and you are using it to deploy a toolstring, then a dropped toolstring  would open it, at which point you have a problem. If you have a tree valve closed, and its not exposed to a dropped object then that's a different case.

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