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.