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Non Return Valves with MPD
11 January 2019

Non Return valves in MPD operations are to be non ported and pressure tested before use.

The reason for this is that with applied annular pressure applied, drillstring connections cannot be made if the float valves are leaking.

During a recent HAZOP planning for a constant bottom hole pressure MPD operation, the operator highlighted that in the past they had experienced float valve failures even with two floats in the drillstring. This resulted in the question how many float valves do we need in the string.  

This raises some additional interesting questions

How many floats are run in the string when drilling with MPD using constant bottom hole pressure

Are float valves shipped from shore complete with test certificates and inspection reports

Are used floats be re-dressed on the rig, if they are, are the redressed floats pressure tested on the rig and to what pressure. Who tests and who is the witness on the test.

Are floats in the string changed every time there is a trip back to surface to make a bit change

If not how long are floats used in the string

Love to hear from service providers and operators of any failures and current practices.


5 answer(s)
jknight
Director
Drilltools Ltd
Total Posts: 2
Join Date: 13/01/19
These days of course we have the advantage of computers and flow modelling software enabling us to optimise flow through the valves and try to reduce solids drop out etc. There is still no guarantee of floats sealing if large debris is present but redundancy and design can help mitigate against debris across sealing faces in an attempt to improve on traditional designs. The addition of flow loop testing (as set out in the API specifications) helps build confidence that the designs do actually work.
learning.lifewayne@g
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 18
Join Date: 25/01/16
One extra thing to keep in mind regarding floats is velocity change and centrifugal forces when fluids with solids are circulated across floats.  If a fluid is carrying solids they can separation out and even leave a layer of solids blocking the device from sealing.  Some discussion relevant in https://www.offshore-mag.com/articles/print/volume-76/issue-4/drilling-and-completion/selecting-opti...  
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 361
Join Date: 10/01/05

How many floats are run in the string when drilling with MPD using constant bottom hole pressure.

A) Two. (HPHT/MPD non  standard more complex wells)

Are float valves shipped from shore complete with test certificates and inspection reports

A) The assemblies were tested onshore or done on the rig with a a BHA QA/QC sheet made supported by charted record of tests and sign off by various parties. (Note: Drillers are reluctant and quite rightly so, to run things below the rotary unless we have such evident to show them all is good to go)

Are used floats be re-dressed on the rig, if they are, are the redressed floats pressure tested on the rig and to what pressure. Who tests and who is the witness on the test. 

A) We would generally change out complete float assemblies if they had been in well for a period to time. DSV/3rd party lead drilling contractor assisting to conduct and witness tests. Onshore we may have a company assigned for all QA/QC assurance of these items.

Are floats in the string changed every time there is a trip back to surface to make a bit change. If not how long are floats used in the string.

A) On most occasions today we plan to drill sections on one trip.If we know section is a two or three drilling bit strategy. We would have one or two back up tested and ready to run float assemblies contracted, and ready to go. if things did not go to plan this affords time to get a.n.other ready in a worst case.   

Further contingent option. 

Drop in darts subs are required to be run with some operators in their BHA's. Darts to be present on drill floor for use when/as required.  

jknight
Director
Drilltools Ltd
Total Posts: 2
Join Date: 13/01/19
Hi Gents (and Ladies)

In my experience, operators are generally using a combination of a plunger type and flapper type floats in MPD drillstrings (one of each in the BHA).

For UBD with 2 phase drilling fluids, we also used to use a third, near-surface float to minimise gas bleed-off volumes.

The interesting thing for me is that no-one actually looks at the specs the floats are made to or certification they have.

Similarly there is not much maintenance done on float subs leading to poor reliability.

There is actually an API spec (API Spec7NRV) for drillstring NRVs, floats and float subs, which very few people use (as it is a difficult specification to meet and no-one wants to invest the money to test to this spec - check it out).

This is also the spec DNV and ABS use as the basis of their respective OS-E101 and CDS certifications for Class rigs. To this end (and at the risk of advertising), I started Drilltools, where we have come up with a new design of drillstring NRV which conforms to both API Spec7NRV and is DNV-GL OS-E101 certified.

The valves are 15k psi working pressure with wireline lock-open capability,  meaning they can be used at surface as well as downhole, you can run wireline through them and they can be stripped through BOPs.

These are stand-alone valves available for 12¼", 8½" and 6" hole sizes, not float inserts and as such have full traceability, maintenance records and certification.

Check out www.drilltools.com for info.

 We introduced the valves to the market last year and have 37 runs to date mainly on HPHT MPD jobs.

In a world of traceability and certification, it is worth checking what you are actually being supplied as most floats have no traceability or certification and limited maintenance as I have found to my expense on a multitude of jobs worldwide.

Cheers

Jeff
________
Note from moderator (Dave Taylor): We don't normally allow "product promotion", but Jeff was good enough to provide a lot of useful comment also, and this product sounds like a "game changer", so we are OK with the content.
SCollard
Director
Welltrain Limited
Total Posts: 8
Join Date: 09/12/09

Steve, 

Interesting questions.  As you know, API RP 92M contains good guidance on use, positioning  and testing of NRVs, particularly when the mud gradient alone will not provide primary well control.


To summarise a few of the recommendations:

  • NRV integrity should be confirmed on each trip out of the hole by pressure testing to the operational pressure the NRV will be exposed to (5.3.6.3)
  • A non-ported NRV should be installed as close to the bit as practical (6.3.1)
  • If the mud system used is hydrostatically underbalanced, a minimum of two NRVs should run in the drill string (6.3.2)
  • Prior to deployment, each NRV should have a low-pressure test and then should be tested to the maximum anticipated working pressure (6.3.3)
  • If a circulating sub is used, at least one NRV shall be installed above the sub (7.3.4) 


It would indeed be interesting to hear how this guidance is applied in practise by different operators and service providers.  My personal experience is:

  • Two NRVs used in general above bit.  One operator had preference for 2 x flapper.  Another operator used 1 x plunger and 1 x flapper with plunger above flapper.  Rationale was that each NRV has a different failure characteristic so using one of each reduces risk of simultaneous failure from a common cause.
  • Third NRV installed above Circ sub has to be flapper type.  Can compromise access to BHA etc.
  • NRVs usually tested prior to shipment to rig; commonly replaced with new NRVs every trip. 
  • NRVs sometimes retested on location if test sub is available


Another common discussion point, both for MPD operations and HPHT operations is whether the NRVs constitute pressure control equipment and, as such, needs to be tested with same frequency as the BOP (and pass pressure tests in the same manner).  Some operators do, others do not.  In practise,  if new NRVs are being installed each trip this is a mute point if the BHA is being recovered prior to a periodic BOP pressure test.  It might only become an issue if using a test ram in deepwater where the drillstring might be left in hole during the test.


Similarly, NRV pressure testing varies.   Some operators test them (close) to rated working pressures (NRVs typically rated to 7,500psi but up to 10,000psi)  while others limit the differential pressure to a multiple of the degree of expected underbalance between formation and mud hydrostatic, or, for MPD operations, a multiple of the maximum surface back pressure that is expected to be applied during connections.  


At the risk of opening out the conversation wider, what about operator’s attitudes towards dart subs?  What is the degree of contingency planning related not only to NRV failure but also washouts – possibly a much more serious issue if a washout happens shallow?

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