Private Forums
Well abandonment: Pumping cement through XT valves
22 August 2018
Dear members,

With well abandonment activity now an increasing  part of life, here's one for you to get your teeth into.

Not everyone has the luxury of re-entering SUBSEA wells where the initial Project team had considered the fact that some poor soul(s) would be called upon in later life to re-enter the wells, after cessation of production, and secure them in perpetuity.

Imagine this.  (And please don't ask "why").

One of the few options left available to you, before you can remove the (vertical) Xmas Tree (XT), is to secure the lower section of the well with a cement plug as one of the barriers required before you can confidently remove the tree and install the MODU x BOP..  You can access the production tubing, but the tree design (and please don't ask) does not allow anything other than circulation/pumping access to the annulus.

You are able to access the Production bore with pretty much anything that you wish, but concerns about the original design of the tree hub (stresses) has made it 'uncomfortable' for you to confidently deploy the full weight/stress of a conventional LRA/EDP all the way back to a MODU.

So you have been thinking about severing the tubing and 'spotting' a cement plug via a LWI riser system (i.e. no coiled tubing).

This means that you may little choice other than to bullhead cement down the system (down the tubing) and to circulate it into place into the annulus, deep down.

However, this means that the cement will pass trrough the XT.,

Do you see the concern?

So, the million-dollar questions are:
  1. Have you faced this challenge?
  2. Have you pumped (bullheaded) cement through the  XT valves?
  3. Did this affect the XT valves?
  4. If not, why not (what did you do to avoid it doing so?)
  5. If it did affect them, please tell us about it and what would you do differently?
  6. What technology exists to get that cement down there without these concerns?
  7. If you've not come across this (just yet!) but have some great ideas how to beat this challenge, then let us know in this open forum, for the  benefit of our industry.
I hope that there are those of you out there that can rise to this challenge.

Best wishes

Dave


9 answer(s)
Bruce Stuart
Various positions from on/offshore service through senior management
Cameron
Total Posts: 1
Join Date: 12/07/17

Dave et al, I note the discussion on subsea well abandonments and recall a discussion I had with a customer who was investigating abandoning old dual bore subsea trees.  The challenge being that the tree valves had not been operated for a long time and as such the client was looking for a couple of valves to land on top of the tree to be a barrier (if the tree valves didn't operate or seal) as well as being able to shear slickline, e-line or if needed coil and seal in the well bore.  This investigation was the opening look at what was on the market and how it could all piece together.

We here at Interventek www.interventek.com have designed and are currently conducting API 17G qualification testing on our Revolution Valve.  It is a compact modular Shear and Seal safety valve designed for In-Riser Landing Sting, Enhanced Landing String / Spanner Joint as well as Open Water Intervention.  The valve is very compact, modular and lightweight.  When running slickline, braided e-line or coil, today’s current ball valve technology may not guarantee a post cut seal as sometimes the ball valve edge is damaged when cutting the intervention media – slickline; braided electric line or coiled tubing.  The Revolution Valve technology separates the shear from the seal so delivers reliable cutting and more importantly post cut liquid and /or gas sealing from 300psi to 20,000psi.

Since the Revolution Valve technology is compact and lightweight (it is lighter than what else is on the market for Open Water work) it was considered as a lightweight barrier solution for this decommissioning / abandonment requirement for these older subsea tree systems where wellhead fatigue is a consideration.  http://www.interventek.com/applications-abandonment-tree.html  

I haven't noted anything in earlier conversations re the impact of wellhead fatigue so thought I'd make everyone aware as I know there are many dual bore trees in the UKCS which will have to be re-entered and this technology maybe a viable piece of the decommissioning / abandonment jigsaw. 

Well_Designed
Project Manager
Well Designed LLC
Total Posts: 2
Join Date: 23/08/18
Dave,

It looks like you have a fun project!

A couple thoughts...

1.  I’ve P&A’d hundreds of surface wells using a , through tubing methodology where cement was pumped through the tree.  I don’t recall a single instance where the function of the valves on the tree were impaired by cement.  I do understand there’s an elevated concern with a subsea well.

2. I would suggest exploring the option of pumping the cement through the wing valves if you haven’t already.  Oceaneering has some tooling that can facilitate this option.  

3.  Oceaneering is developing riserless open water coil tubing capability.  If the timing of this work is flexible, this could also be a good solution.

I’m happy to elaborate on any of the above if there are questions.  


Regis STUDER
General Manager
DrillScan
Total Posts: 10
Join Date: 27/02/16
Playing devil’s advocate, the Romans proved us the cement integrity over millenaries. We have not this chance with resin and besides the fact that it looks tricky to succeed placing it downhole as required. I would favour cement slurry solutions the industry masters much better. Sound P&A requires the restoring of natural barriers.
 
Back to Dave Taylor's challenge, in desperate situation where Subsea XM functions cannot be compromised (well integrity issues), the (multi) million-dollar solution is a re-entry relief well to place the required barrier above reservoir. One will then be fine to remove the XT and proceed with P&A. Hopefully Dave you are not in this situation.
Régis
learning.lifewayne@g
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 18
Join Date: 25/01/16
Interesting how the industry and regulators are dealing with well system decommissioning.  Back in the '70's some major operators had a operational philosophy of leaving the sea floor as you found it.  Unfortunately the design of many subsea well systems have not been designed and completed to make the recovery process easier.

My experience is that you have no chance of getting a seal of the reservoir by bull heading cement.  Two things are likely with the well system. 

The production casing will need to be block squeezed to assure there is 150 ft of barrier above the top gas zone the depth of which should be verified using the ASCII mud log data and

secondly there will be gas under the wellhead behind the production casing.  

My thoughts are that the industry with the World Bank should add a fee of 5 dlrs / bbl and 20 cents / mmcf gas to cover the cost of decommissioning to where the "location" of the well system is at worst the way it was found.  


learning.lifewayne@g
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 18
Join Date: 25/01/16
Interesting how the industry and regulators are dealing with well system decommissioning.  Back in the '70's some major operators had a operational philosophy of leaving the sea floor as you found it.  Unfortunately the design of many subsea well systems have not been designed and completed to make the recovery process easier.

My experience is that you have no chance of getting a seal of the reservoir by bull heading cement.  Two things are likely with the well system. 

The production casing will need to be block squeezed to assure there is 150 ft of barrier above the top gas zone the depth of which should be verified using the ASCII mud log data and

secondly there will be gas under the wellhead behind the production casing.  

My thoughts are that the industry with the World Bank should add a fee of 5 dlrs / bbl and 20 cents / mmcf gas to cover the cost of decommissioning to where the "location" of the well system is at worst the way it was found.  


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

Dave

Just talked to Alistair Paterson from R&D Solutions in Australia at the IADC Drilling Conference in Bangkok with regards to the Sandaband product, he had a sample of Sandaband with him at the show. This offers an interesting solution to abandonment. Although not used it myself, so have no experience in actual deployment of the Sandaband product. The challenge for this case is that it does need to be placed at location by pumping. So for your case that would require coil intervention which is not an option.

The only other option that I can see as open is a resin sealant such as Wellock . Although expensive, the advantage of resin is that it can be mixed at surface to a higher density than the fluid and dropped into the top of the well. It will freefall through a waterbased fluid (it has a higher density) and settle at the bottom effectively sealing the well. This has been used both in annuli and in tubing and works very well as a barrier. The advantage of resin is that it is gas tight and durable and it does not need to be placed by pumping. It can be placed into the well at the tree using a dump bailer if required. On land wells we have literally dumped the resin into the well with a bucket.

The resin will bypass any obstructions and will settle at the bottom of the well. Some work will have to be done on timings and how fast the resin will freefall through the fluid (depends on the density difference)

Need to make sure that there is accurate temperature data on the well as the resin needs to be mixed to ensure that it hardens after it has reached the bottom of the well. The fluid in the well needs to be waterbased as resin does not work in oil based fluids so the well needs to be killed and cannot contain any reservoir oil in the tubing.

admin
Managing Director (rp-squared.com)
Relentless Pursuit Of Perfection Ltd.
Total Posts: 413
Join Date: 10/01/05
Thankyou Steve and Pete for your answers.  

I am sure that there are other members out there who have something to contribute. Whilst I don't like anonymity, you can always email me (dave@rp-squared.com) and I will post it for you (without mentioning names, companies etc)

Both Steve and Pete faced significant challenges!

One of the challenegs being faced in this instance is that there is a possibility that the 9⅝" production casing may have suffered corrosion to such an extent that it could be unwise to apply pressure to it in case it bursts, which would complicate matters somewhat.

The trees must be removed for a variety of reasons, not least being that they are vertical trees and the tubing needs to be recovered to effectively secure several of the annuli.

Circulating cement into place was an option, but concerns about the tree and intervention package valves caused that idea to be put back on the shelf.

Other options being considered are:
  • Sandaband
  • Coil-hose
  • Wel-Lok
What experience do members have with these products?

I am likely to have more questions/information after facilitating this week's 2-day Review. The client has assembled ex-Regulators, LWI experts, Well-Control/Eequipment-Developer experts to brainstorm potential solutions.

We're looking forward to your responses.

Cheers

Dave

Pete Thomson
Decommissioning Projects Manager
BHGE
Total Posts: 6
Join Date: 12/12/15

Hi Dave – as you know I was Drilling Superintendent for the 30 x subsea well abandonment campaign in the UKCNS.  We had a LWIV campaign on 15 wells to set suspension plugs and remove the trees.  15 were abandoned using a semi-sub only with the EDP / LRP used to allow setting of deep and shallow barriers to recover the trees.  

One of these wells had a drift and 9,800ft of slickline encased in Barium Sulphate scale from 6yrs of high water-cut production with substantial overpressure.  This meant we were never going to get any type of deep-set tubing plug down there, nor could the well be sufficiently stabilised with 12.4ppg NaCl brine.  We opted to bullhead cement from surface through the EDP / LRP and tree to effect a deep suspension barrier.  Additionally, since we had to recover the tubing by pulling out of a PBR, we couldn’t risk any cement being left too far up inside the completion – we therefore ended up with 2 cement jobs – try evaluating that “under-displacement” through tubing with an unknown thickness of scale!! The first attempt was therefore slightly over displaced and partially isolated the reservoir as shown by the change in parameters.

Therefore:

The challenge for us was two-fold - in making the decision and in conducting the cementing operations

We bullheaded 5bbls and 30bbls cement through the production bore of the DBR, the tree and EDP / LRP and down the tubing into the formation

Since we had an LRP, we had back-up to the tree valves should they have failed.  However, we didn’t want to operate the tree valves during the job to keep them “pristine” in case we had to recover the EDP / LRP leaving the tree as the Barrier again. 

At no time did we strip down any trees since they were off for scrap, but we did strip down the EDP and LRP.   Despite designing the rheology and thickening time of a slurry which was as suitable as we could make it, plus including a rigorous clean-out using the annulus and production bores of the dual bore riser and swopping bores via the XOV, etc. the EDP / LRP was still partially cemented up, requiring new valves and seats.

The tree valves could easily have been affected in the same manner.  However the production bore tubing hanger plug set first time with no issues.

Our primary plan was definitely not to go cementing through the tree and we wouldn’t want to plan on this basis.  This means of putting the cement slurry in place is not a technical solution giving a satisfactory level of verification for a long term permanent barrier.  Its additionally exacerbated by not having an annulus to remove cement should something go wrong.  For scaled tubing you don’t know exactly where the cement will end up and likewise if you had parted or leaking tubing.  And of course we’re putting cement through valves we may require later in that operation.

Having said the above, needs must in a particular well’s circumstances and it sounds like yours is one of them !!  

As for the job itself, I can’t disagree with what Steve Nas has posted should you need to go down that route…….there’s some great information there.

Hope this assists.


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

Dave

Have faced this challenge a few times

Instead of removing the tree, leave it in place and use a light well intervention (LWI)package. That is a much better solution than removing the tree with all its issues and then installing a drilling subsea BOP.

A light well intervention package allows access to the well so that investigations can be done, and plugs can be set. It also allows better options for selectively perforating if required.

If required cement can be pumped down the flow line and down the tree and into the tubing.

But the issue becomes the bigger picture. Ideally the caprock needs to be restored to abandon a well so depending on the well configuration and the location of the packer there may be a requirement to seal the annular space below the packer. With a packer set in the 9-5/8 and a 7 “ liner across the reservoir there could be a liner hanger below the packer. A potential leak path from lower reservoirs.

The location of the caprock in the well needs to drive the lower abandonment

Although normally a well intervention package is connected to the subsea tree, even without a subsea well intervention package, the lower abandonment can be done with the tree in place. But it does require access to the tubing (flow line) and the “A” annulus (kill wing ??)

Assumptions

  • The well is live to the tree and reservoir fluids are inside the tubing
  • The Tree is functional, and the tree valves are operable and are pressure sealing.
  • There are no sand screens
  • There are no inflow devices or smart completions installed
  • There are no hydrocarbons in the annulus above the packer

Step 1

Perform Tubing diagnostics

This done by pressure testing the “A” Annulus to 1000 psi to check integrity of tubing and packer.

This ensures that the tubing and packer are in good order and that pumping down the tubing does not result in annular pressure in the “A” annulus.

Once the tubing and packer are confirmed as good

Step 2

Record rate of injection down the tubing to determine viability of injecting cement into the formation (Squeeze Plug). If the well has screens installed it will be likely that the tubing below the packer needs to be perforated to get injectivity, in which case an intervention package will be required.

Step 3

Upon confirmation of injectivity, Bullhead the tubing reservoir fluid with water into the formation.

After displacement of the tubing fluid, reconfirm that annulus integrity is still good.

Set up to perform squeeze plug

Step 4

Cement will have clean fluid gel spacers in front and behind to minimize contamination

A typical rate of injection to perform the squeeze is a minimum of 2.5 bpm @ less than 3000 psi.

This will vary depending on water depth, tubing size and reservoir properties

Batch mix, pump and displace cement.

Top of cement to be below the packer

After waiting on cement for 12 hours pressure test tubing with 1000 psi from above.

At this point you have a barrier in the tubing (the cement plug).

The next option would be to run into the well and perforate the tubing above the packer and set a 500 ft balanced cement plug above packer.

This can be done with a well intervention package installed on top of the tree.

The full wireline abandonment scenario has been done both in West Africa (8 wells) and in the GOM (9 wells) but with a well intervention package

See https://www.oedigital.com/energy/item/12790-a-new-way-to-p-a

Pumping cement through the tree is generally not an issue, the tree will be removed and recovered most of the time. As long as the tree valves can be opened (and closed if need be).

A bigger challenge was encountered offshore Africa where all of the tree valves were leaking and the tree cap could not be removed. This was eventually resolved by bullheading kill fluid down the flow line from the FPSO to the reservoir. Once the well was killed the tree cap was removed and a LWI package was installed, and subsequently deep set plugs were installed the tubing with wireline.

It really requires out of the box thinking to effectively abandon a subsea well and try not to get locked into the removal of the tubing. Most wells can be abandoned leaving the tree and the tubing in place. In deepwater there generally is no issue leaving things in place provided that the hydrocarbons are removed from facilities at the seabed.


Jump to top of the page