Matteo makes a good point in that if you have sustained annulus pressure ( SAP) , then in effect your annulus line valve is no longer a 'secondary barrier' element, it has become a 'primary barrier ' element.
This situation is addressed in gas lifted wells, where the SAP is planned, and Norsok D10 recognises the mass of gas contained in the A annulus (TCA) as being significant enough to require a double barrier to prevent its release.
In these cases OPCO's are increasingly installing surface annulus safety valves in the wellhead side outlet VR profile. The surface annulus safety valve provides a primary barrier to the release of lift gas from the a annulus and the annulus line gate valve the secondary barrier.
Given the risks associated with the release of lift gas are usually greater than the release of SAP in a liquid filled annulus then it is reasonable to adopt this approach in wells with SAP too.
The option to manage the SAP autonomously is also available as shown via this link .
http://www.ptc.as/solutions/wellhead/a-pro-annulus-pressure-management-system
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Alan Brodie
PTC Middle East Region Manager
Abu Dhabi
Original Message:
Sent: Jul 20,2016 03:03 AM
From: Matteo Loizzo
Subject: Pressure testing annulus valves
Hello Kurian,
I would go back to basics: your wellhead annulus access valve is part of the secondary barrier and should be monitored to ensure it is working whenever you need it. Since it's a weak spot for material ageing, it is routinely operated and it can fail if it doesn't open, system reliability (i.e. you don't want major leaks to surface) calls for periodic monitoring to avoid hidden/dormant failures. For instance, NORSOK D-010 requires that "annulus valves shall be leak and function tested frequently".
So when you ask if you can use the (possibly sustained) annular pressure to test the valve, the short answer is "yes, but". In fact you need to leak test the valve, i.e. you want to ensure nothing flows out of it under the pressure difference. This can be achieved by attaching a fixed volume container with a valve downstream from the tested valve, or by characterising the leak that causes the pressure increase in the first place.
If the annulus is recharged only slowly, then steady annular pressure means at most an acceptable leak. How small an acceptable leak is can be taken from API RP 14B (15 ft3/min for gas); or from the US federal code dealing with deepwater Gulf of Mexico, which requires that pressure takes longer than 24 hours to bleed from >100 psi to 0 through ½" needle valve (30 CFR 250.525). API rule comes from considering a flame that can be put out with a standard fire extinguisher, but there may be other risk factors you want to consider to come up with your own acceptable figure.
So if the annular leak is small enough, then you may leak test the valve using annular pressure.
However the real issue is whether you should live with the annular pressure in the first place, since this means the secondary barrier is now your primary one. There are at least two criteria to be fulfilled for the risk to be acceptable:
- The first barrier is resilient, i.e. it failed but retains the ability to control the flow. I don't like hard and fast rules in risk management, but if you must, then use API RP 14B criteria.
- The presence of reservoir fluids at the wellhead doesn't cause ageing and premature failure. Many things can degrade steel and elastomers, so you should look at the exact composition of the fluid that's causing casing pressure. As a rule of thumb you do not want oxygen or CO2, which can eat through steel fast when water is present. Remember that a pierce wellhead is worse than a failed valve.
Hope it helps,
Matteo
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Matteo Loizzo
Well integrity consultant
Berlin