The standard practice in our company is to run intermediate 9 5/8" casing in one string, but cement them in two stages with stage tool and production 7" casing is usually run in two strings (liner with tie- back).
Due to the last time failure with stage tool, the one of the primary targets for our team is to eliminate stage cementing or tie- back liner approach and apply advanced cement technology for our next wells.
The challenge is to cement casing in one stage up to the surface, without losses or formation fracturing and preferably without reducing cement integrity in HPHT environment.
Information for intermediate 9 5/8" casing1. Depth 4670m
Information for 7"production casing
1. Depth 5400m
2. Temperature at the bottom up to 155 Celsius
3. Formation pressure 14 500 psi
4. Previous casing shoe 4670m
5. WBM, mud weight 1.90spg
In both cases the cement slurry should be pumped up to the surface according to the requirements of local legislation for gas wells.
Does anybody have an experience doing cement job in one run in similar conditions?
appreciate if you could share with us which technology did you use?
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.
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