Q&A No.710 - Suspend & Kick Off Wells in Brine?

0 votes


For substantial cost savings, Husky is considering starting up our subsea production wells to the FPSO with overbalanced brine in the wells as the suspension fluid.    Eliminating the need to displace to underbalanced base oil would allow us to land the completion with the tubing hanger crown plug pre-installed, and would significantly reduce surface rig-up requirements.

The brine would be overbalanced NaCl or CaCl2 in the density range of 1070 to 1250 kg/m3, depending on the well/field.  We would kick off the wells by N2 unloading the annulus through the gas lift valve, N2 being supplied via subsea intervention vessel.

Our initial concerns were hydrate formation, chemical compatibilities, and discharge approvals.   We are looking into the addition of MEG to the brine for hydrate inhibition, which appears achievable for our predicted pressures.

Does anyone have any similar experiences to share kicking off wells with overbalanced brines, and flowing brines back through the subsea and topsides production system?  Any concerns?

Thanks in advance for your insight!



Dan Schoonhoven

Sr Completions Engineer

Husky Energy; Atlantic Region

asked Feb 22, 2016 in COIN by Dan Schoonhoven (390 points)

4 Answers

+1 vote


We flowed back some subsea wells to a rig until we had hydrocarbons to surface then shut down. The final clean-up was conducted to the platform. This approach meant we did not have to deal with hydro-carbons on the rig and the well was sufficiently live to flow straight to the process.


Fraser Martin


NOJV Drilling & Completions Engineer

answered Feb 23, 2016 by Fraser Martin (280 points)
Hi Fraser, interesting approach!  However, we're aiming to run our completions with the tubing hanger plug pre-installed, and therefore don't have a circulation path to be able to lift the well to the rig.
+1 vote


Nitrogen hydrates form at very high pressures so I don’t believe this should be an issue, also the brines you are looking at using have their own inhibition properties (i.e. salts).

Standard MeOH or MEG or KCl injection at the tree should suffice until the THT is sufficiently outside the hydrocarbon hydrate envelope.

MEG can be very damaging to some reservoirs, has there been coreflood done to test this? In essence, I wouldn’t advise this. I have kicked of many wells with overbalance brines and have not had to resort to this.

The main thing here is to understand the dissociation hydrate working envelope for his hydrocarbon / reservoir and inhibit / inject until outside this point (i.e. temperature) at the tree.


Gary E. Cooper

Petroleum Engineering Advisor

Ithaca Energy (UK) Limited

answered Feb 23, 2016 by Gary Cooper (160 points)
Hi Gary, good to hear your experience with this.

We haven't done any core compatibility studies.  Our rational was that there is sufficient RDF volume remaining between the open hole and the brine interface that brine would not have a chance to reach the reservoir before the overbalance equalized out.  That being said, we'd still rather not have to use MEG - we'll take a 2nd look at our startup conditions and see if we are comfortable enough with wellhead treatment only during startup.  We did make some conservative assumptions.

+1 vote

I don’t know what the water depth is or the fluid(s) you will be producing, however, my immediate concern is that Husky sights are firmly set on cost savings in operational time, but, may not have fully considered the impact of flow assurance (short, medium and long term) and the impact of hydrates at various locations in the well and flow delivery system.

Tullow Ghana had a water depth of 5,000+ feet, rigs were not readily available and were hugely expensive so any time savings were reviewed and seriously considered. But, a hydrate plug formed some years ago, and despite many efforts I understand it is still there.

The impact of this did not impact production directly, but did cause significant well integrity issues as the annulus on several wells could not easily be bled down.

So, I suggest you consider the entire system, and determine what wold be the impact if a hydrate formed at key points, how could it be mitigated or how could it be removed.

Good luck in these challenging times.

Best regards

answered Feb 24, 2016 by Simon Sparke (160 points)
Thanks for the feedback Simon.  We will be conducting a risk assessment with relevant parties - production, subsea, etc to get everyone thinking about the broader system.  Certainly don't want to end out with hydrates anywhere!
0 votes

I would agree with Gary’s comments, ref the hydrate inhibition at wellhead and the fact that some reservoirs don’t like MEG, that would be a check that I would definitely recommend.

My experience with looking at these things in past is that the production people get very nervous when you talk about flowing to host for the unloading of a subsea well, the first concern if it’s going back to an FPSO is solids going through the turret swivel and untimely damaging it, you defiantly don’t want to end up in that situation, the second part is can the production train handle the volume of brine/meg coming through, issues there are,

·         Handling the volume of water.

·         Blocking up lines within a separator.

·         The mixing of fluids in the process train- would not think brine would be an issue but I have seen emulsion problems with flowing back scale treatments.

·         MEG in the oil can be an issue for when sold and there could be penalties to pay.

I normally see once the above are taken in to consideration that the wells end up being unloaded  to rig, the key is engagement with the production department and get them onboard on how they going to handle it and ensure they have a plan in place with all the risks looked at on how they going to do it, I have seen this being agreed with no thought from the production side and when it comes to it they get cold feet and you end up flowing it to the rig at the last minute!

Last thing,  you mention using a vessel to pump N2 and lift via Annuals- I would suggest early engagement with a vessel provider on how they going to do that as it may require the procurement of specialised lines for pumping N2 etc, what kind of vessel would it need to be, for example if it needs to be an LWIV that is required is there one in your region? There could be costs there that you are unaware of.

Lastly, how is the is the connection to the Tree Annulus going to be made will that be a pre-designed connection on the tree, for example, a bit of up front thought here could save a lot when it comes to doing it.



Euan McConnach

Eswell Ltd

Subsea well intervention engineering and project management.

answered Feb 24, 2016 by Euan McConnach (140 points)
Hi Euan, thanks for sharing. I'll discuss your notes with our production group, hopefully we can address everything.

We have actually N2 lifted our last 2 wells via vessel ROV intervention with a downline for the N2, so we have all the required equipment etc. We needed to lift  these prior wells because although they were suspended in underbalanced base oil completion fluid, the horizontal ICD sections of the wells contained sufficient RDF volume to kill the wells once it moved up into the production tubing.

By "connection to the tree annulus", are you referring to the connection for pumping N2?  If so, our horizontal XMTs have a TCT line hot stab that the ROV connects the N2 downline from the vessel to. The N2 is then directed into the well annulus via the AMV valve.

Thanks again,