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Reducing or eliminating SAP (Sustained Annular Pressure)
02 October 2015
We've received this request from a group who would prefer to remain anonymous.

The Operator has wells with Sustained Annular Pressure (SAP) on the "B" annulus on newly drilled and producing wells.

Does anybody in the SPREAD community have experience in reducing or eliminating the B pressure by conducting a Lube and Bleed operation on the B annulus with:

1 - Water
2 - Viscous fluid
3 - Kill Weight Brine

Last resort is a perforate and squeeze operation. 

Any feedback would be appreciated. Results can be shared. 

Thanks

Dave
5 answer(s)
SteveNatResPro
Drilling Engineering Advisor
SPREADAssociates
Total Posts: 3
Join Date: 17/09/15
For the producers it looks as if the 9⅝" cement job has failed. Was cement brought back to surface, prior to plug bomb what was the displacement pressure telling you about a cement top, were there losses, did the plug bump, was there an back-pressure, did you run any form of CBL or USIt to evaluate the cement? I assume the shoe-track was not drilled out  as this was a production string into which tubing was run. Can we assume that the C annulus (13â…œ” x 20") is competent? (i.e. is there are gauge on the wellhead SOV, and does it read 0 psi). Although this could be assumed to be the case with a new well I remember back to my well integrity days and found that a number of older wells I tested had communication between multiple annuli. You really do need to think about a pressure test on the 9⅝" x13â…œ” - this will tell you a lot. Obviously within the safe limits of your burst and collapse rating, but it will indicate whether or not the annulus supports a fluid column, and at what fluid density. You will have to perform a fairly long duration test to be sure that you're not loosing fluid. Once you've established that there is no fluid bleed-off you can lubricate a a fluid with this density into the annulus. You have at least established a temporary solution. If the annulus doesn't at least support a column of water then anything heavier will bleed into through the leak path, and therefore you'll eventually go under-balanced and invite further gas ingresses. If your pressure test indicates that you have a reasonable degree of bleed-off, and this is below or close to hydrostatic, then you will be fighting a loosing battle putting any fluid into the annulus. Anything that's highly viscous could plug off near to surface, and this will mask your issue - and is highly likely to cause a casing failure below the plug. If you have good infectivity it would be well worth injecting a fluid that is likely to plug off the formation, such as a high density drilling fluid with a very poor gel structure - something that would let the weighting material settle out quickly. Barite plugs are very effective. At 500 m your13â…œ” casing shoe is at coming depth for wells used to re-inject cutting on offshore platforms, so once you've confirmed that you have a down-hole leak off there should be no reason why you can't get something that will likely plug off down the bottom of the annulus.
henning
SPREADAssociates
Total Posts: 2
Join Date: 11/02/10
This is indeed an interesting topic, and apparently there are not any real good fix for it. 
I know Cameron had a system years ago where they could displace heavy fluids into the annulus with SAP. However, as far as I have heard it was shelved due to lack of clients taking it into use. I guess that the problem really is not large enough for the operators to invest in a solution?

Being an inventor and a serial entrepreneur, I would love to study the problem better to see if I and my network can come up with a solution that can easily and at low cost be implemented. The work I do now typically consist of coming up with solutions that is then taken into the market by one or several service companies.

So if anyone is interested to share info with me, I would certainly be very grateful. Info about who has the challenges and contact details and wellhead schematics will be very helpful.
My email address is [email protected] 


admin
Managing Director (rp-squared.com)
Relentless Pursuit Of Perfection Ltd.
Total Posts: 376
Join Date: 10/01/05
Hi folks

I have some more information.. 

"Further definition on the annulus with the SAP:
  • In producers, two casings are run after the 20” conductor: 13â…œ” Intermediate at ~500m  and 9⅝” Production string at ~1200m.  There is a 4 "” tubing string inside the 9⅝” casing. The pressure is in B Annulus = annulus between 13â…œ” by 9⅝”.
  • In the Injector two casings are run after the 13â…œ” conductor: 9⅝”  Intermediate at ~500m and 7” Production string ~1200m, no completion is run.  The annulus of concern is the annulus between the 9⅝” by 7” casing

The fluid being bled off is gas. 

The pressure can increase or decrease after starting a lube & bleed operation. 

Usually there is no liquid to bleed off until sometime after the inhibited water has been injected as part of the Lube & Bleed operation.

The casing pressure can be over MAASP so this has to be managed. "

Thanks

Dave

gbsgovindan
Workover Supervisor
Cairn India
Total Posts: 2
Join Date: 05/05/15
Steve has given a good account of the possible reasons how the B-annulus can develop SAP. I have come across this problem in quite a few fields, and at least on 2 such fields (under two different Operators), the "Well Service Teams" manage the issue by lubrication with water. They have teams specifically for this task of lubricating the annulus. They found out that the SAP issue has many possible reasons and permanent solutions are rare, hence the decision to survive with the problem, judiciously managing it.
SteveNatResPro
Drilling Engineering Advisor
SPREADAssociates
Total Posts: 3
Join Date: 17/09/15
Dave,
I used to have responsibility for this issue, and investigated a number of possible solutions, but most depend on the circumstances behind the SAP.
Firstly a lot depends on the source of the pressure - is it a casing leak, poor cement job, or simply that exposed formation actually has a pore pressure greater than the hydrostatic of what's currently in the annulus.
Is the annulus full, or has a drilling fluid separated with the weighting agent settled out at the bottom of the column? Settled barite forms a remarkably good plug, especially when exposed to a little additional pressure from above.
Clearly anything done on the annulus has to conducted within the basis of casing burst and collapse pressures. Was the outer annuli ever exposed to any form of casing wear?
Water is unlikely to do anything. Presumably this was in part the original annulus content. Viscous fluids are also unlikely to be part of the solution, it would take a particularly good gel structure to have any permanent affect. Lubricating something that is highly viscous could result in a near surface plug - making the situation far worse.
Kill weight brines would be a far superior option, provided of course any corrosion issues are considered.
Further to your initial list, it would make sense, depending on the circumstances behind the SAP to perform an infectivity test. If the possibility exists to inject fluid into the leak zone, there is likely a far higher success rate to plug both the source, and ensure that the annulus can be filled.
There are some specialist products on the market to plug charging annuli. Sandaband is one such product. I performed a number of highly successful tests nearly 10 years ago. I'm quite confident, that since then there will have been numerous case histories on successful SAP cures.
Hope this helps.
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