Viktor, 

For easier well control I would always run a 7” production liner in a HTHP well as you last casing string.

So in your well figuration for your 9 5/8” production casing the major concern when well control is required to prevent subsequent problems when there are producible permeable gas zones that need perforating behind the 9 5/8” casing.  If you need to cement to surface I would recommend a foam cement operation.  Most operators will normally ensure a top of cement of 150m to sometimes 300m of cement above the highest gas production zone

Difficulty of your well depends on whether you have flowable hydrocarbon behind the 9 5/8” casing and what height you need you cement above the highest production zone.   

With a foam cement you can:

A)     Vary the base water composition to ensure cement properties

B)      Vary the foam concentration to alter the slurry weight. 

Main benefits of foam cement are reduced hydrostatics (loss circulation solution), thermal insulation, gas migration control and more recently prevention of thermally induce stress cracking. 

In addition there is a concern when you have non producible but permeable zone present gas can travel up the casing and you will be left with pressure on your B annulus over time. The importance of the production casing has been of concern over recent years to operators and regulators

I have worked on some very high production rate high pressure gas wells in the past. Due to well failures and inability to achieve functional specifications I have seen the need to use more and more foam cementing to solve well problems on deep-water wells, HTHP gas wells and cyclic steam wells.

So in one offshore HTHP well we have cemented to surface in the past we used a lead slurry of 1835kg/m foamed down to an average of 1634kg/m3 (variable density in the column as constant nitrogen used). The tail slurry was 1950kg/m3 Class G silica flour fresh water foamed down to 1684 kg/m3. Total well depth is approximately 4500m with a BHST of c. 140 Centigrade, final mud weight 1825kg/m3.      

Foam cementing is not without issues but I would consider it the most safe and economic option for these type of wells. You do need to have the equipment, cement technical personnel, laboratory testing and technical authority in a place to get success. At present foam cement is preferred in North Sea, Norwegian Sea wells, Gulf of Mexico wells and Eastern Canada HTHP wells rather than stage tools.   I have very limited experience of stage tools.     

 Unfortunately interpretation of CBL logging are highly doubtful in foam wells.  

 I’d advise you to ask the regulator to give you the reasons why there is a need to cement all the well to surface. We have certainly reduce cement height requirements where buckling was the issue by having constructive discussions with the regulator.  You should also ask the regulator to give you a regulation on the top of cement required above any highest gas zone exposed in the 12 ¼” 9 5/8” annulus.   

In a number of published papers on cyclic steam wells you can see the benefit of using foam cement to get cement to surface thus reducing the risk of well failure. There are a few published papers on foam cementing in HTHP wells.  

Viktor, I don't believe on the basis of a failure that you should simply try to eliminate stage cementing collars and move to a different process. I would do a detailed analysis of why the last stage collar may have failed, find the root cause, implement mitigation then find a reliable stage collar system, plan the job properly, with checks and balance to provide assurance and ensure the job is executed as per plan. Switching to a new system or process will just expose you to a different set of risks and exposures. Stage cementing collars have been around for decades, jobs are performed successfully everyday. You may have a complex job and you may need a premium stage collar, but I feel confident you can stay with a stage collar if you manage it properly.

Hi Viktor.

Others are more qualified to discuss cementing such a length of casing, but my comments are from an abandonment point of view. 

As part of our well design I'd suggest you have a look at what the formations, pressures and connate fluids are telling us to do in terms of primary and secondary barriers.

Intermediate strings cemented to surface can pose difficulties at the end of the well life if we need to barrier off a shallower zone which hasn't been adequately barriered off in this cement operation.   We therefore can't pull our cemented-to-surface 9-5/8" casing, an extensive milling operation from surface isn't preferred and we're therefore into section milling country since the effectiveness of perf / wash / cement (PWC) certainly isn't guaranteed in a partially cemented section.

However, even this may be a mute discussion dependant on the desire to run 7" production casing and also cement to surface - that needs to be taken into account in this abandonment well design too.

My experience of HPHT wells going back to the mid 80s is that we selected to run a 7" liner and tie it back primarily because we didn't have to get the casing hanger landed out thereby reducing risk of having to pull 7" casing back to surface again.  The tieback seals didn't leak and the abandonment plan is more flexible due to 7" being uncemented. 

I hope this assists you..........best regards

   

Hello,
You may consider the use of light weight cement (a combination between two slurries in fact). The use of cenosphere can reduce the cement density to accomodate your ECD issue during cement job. You'd better see with your cementing company what are their solutions for your challenge.
Regards