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Material selection philosophy for casing
11 January 2010
I'd like to get the forums views on the philosophy for the selection of casing materials in the case of an onshore HPHT project with a reservoir fluid that is moderately sour.

In a conventional well that is completed with a packer and tubing string, little or none of the production casing is ever exposed to reservoir fluids. Only in the event of a failure of a primary barrier (hanger, tubing packer etc) is the production casing exposed to such fluids. As such, what are the philosophical or policy approaches used by other operators to guide selection of a suitable casing material?

Bruce Richardson
4 answer(s)
Well Engineering Manager
Total Posts: 30
Join Date: 30/06/08
Bruce, we recently went through a long series of conversations about this issue. The result of the dialogue concluded that since we could not guarantee that the casing would not come in contact with H2S (packers and tubing failures do happen), we are using H2S compatible materials (we went with a Sour Service T-95) where temperatures in the well suggest materials will be susceptible to H2S and P110 grade materials where temperatures are expected to be high enough to be outside the stress cracking region. This decision was made on the basis of a hazard identification and risk assessment of the project with a life cycle value approach. The production operations team did suggest that later in the well life it may be required to operate with the packer open and that together with negotiating favourable pricing made the decision much easier. That said, our well design team came to the conclusion that the sour service materials were important even with the tubing and packer. Our company has a 2 barrier policy that requires VP approval to obtain a variance.

David White
Well Construction Performance Champion
Total Posts: 1
Join Date: 07/01/10
I have not seen any policy addressing this issue in any of the organisations I have worked in. The following is a personal perspective.
From an "optimum" perspective you should engineer your production casing to match the produced fluid environment over field life. This is not common practice as the cost v risk reduction cannot normally be justified.
We tend to be less conservative if there are other methods to protect the casing (an example is the misting corrosion inhibitor into lift gas in gas lift applications) and if the pressure / temperature / fluid property environment is not extreme.
In a more conventional application, you could minimise the cost impact by ensuring that the casing where your production packer is to be set is capable of handling the produced fluid environment over field life.
However, given the GDY operating environment and the potential for increased souring of the reservoir over field life (via contamination from the injected fluids), I believe you should err on the side of caution and design the entire string to meet this criteria.

Nick Muecke
Drilling Engineering Mgr
Maersk Oil
Total Posts: 16
Join Date: 15/01/09

From my observations, I don't believe there is consistency in philosophy regarding this from one company to another. My own view is that I would not design the production casing material above the packer to be suitable for production fluids, however I would ensure that it has premium connections to allow for the possibility of a gas kick when drilling the reservoir. I would add a couple of caveats to that statement however: a) if high hydrogen sulphide levels are expected in the reservoir I would consider that in the casing selection due to the possibility of a gas kick, and b) the risk of tubing or production packer failure should be risk assessed: with the history of problems with HPHT service and the cost of HPHT wells, the added cost of higher grade production casing may be worth paying.

Derek Charlton
Drilling Mgr (semis)
Maersk Oil, Aberdeen
Well Test Engineer
Total Posts: 5
Join Date: 11/03/09
You say the prod casing will only be exposed to sour fluids on failure of a primary barrier - while in essence this sounds true, over the life of the well there can be exposure through micro leaks both internally & externally.
Additionally, if your primary barrier fails, you really do want to have 100% faith in your secondary barrier so this envelope too needs to be sour service.
There are a host of high strength SS materials available - not knowing the essence of your design first recommendation is to pull in your vendors for a discussion on what they can supply.
Don't take shortcuts with HPHT...

Neil Sultan
Welltest Engr
Posted by

Bruce Richardson

Lead Drilling Engineer

British Gas

Total Posts: 10
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