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How to avoid multistage cement operations in long intervals of casing?
30 June 2019
Dear colleagues,

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" casing

1.  Depth 4670m

2. Temperature at the bottom up to 125 Celsius

3.  Formation pressure 8100 psi

4.  Previous casing shoe 2250m (with LOT pressure 5000 psi)

5.  WBM, mud weight 1.25spg

 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.

So, my question is:

Does anybody have an experience doing cement job in one run in similar conditions?

I would appreciate if you could share with us which technology did you use?

Best regards,



5 answer(s)
(retired) Well Fluids Team leader
SPREAD Associates
Total Posts: 57
Join Date: 14/06/06

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.  


Total Posts: 117
Join Date: 10/04/08
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.
SPREAD Associates
Total Posts: 7
Join Date: 21/09/10
Victor, some suggestions:-

There a couple of ways to eliminate stage cement. One way using lightweight cements which are normally water extended, however once cement density gets below 1.3 sg or so then it would not be regarded as competent. When you require lower densities in order to stay within ECD you could choose either cenospheres or foam cement which can be used to reduce cement density and lower ECD while the slurry remains mechanically competent.

Another solution is reverse circulation cementing, pumping down the annulus and taking returns up the casing id, which will lower the friction pressure and thus reduce the ECD. 

Generally cenosphere are operational easier to do and foam cement requires good equipment and operators. Reverse circulation cementing requires specialised floating equipment and may require covering the well control issues that can be present in this operation. Which might be used depends on your circumstances and the availability of equipment and expertise. 

In the case of the 7in Liner/tieback then the only option that that I know of which may eliminates a tieback is using reverse circulation of cement. You do not quote the fracture pressure but my experience is that in HPHT wells the difference between formation pressure and fracture pressure is small.  Again specialised equipment would be required and well control issues need to be covered.  There also appears to be a very small margin between formation pressure and mud density in this hole section.

I came across an unusual Liner tie back cement job where there was a situation that the job shut off prematurely. After some study it may have been that the liner lap cement fractured and the cement squeezed off. The long tieback was cemented to surface with 1.92 sg slurry with a relatively narrow annulus. After simulation the ECD was calculated to 2.34 S.G.. the liner top was tested before cementing the tieback to 2.08 sg so one scenario was a fractured liner top cement lap.  It may be worthwhile to ensure that if a liner / tieback is run that the liner top can be tested to withstand the ECD while cementing the tieback to surface.

You might also look at the effect of temperature on all of the strings in the well as when on production the temperature can rise to levels in upper casings to above 110C. On one  HPHT well where the BHT was 210C the conductor casing temperature was modelled at >110C during production and silica was used in the conductor cement slurry.

These are some suggestions that you can discuss with the cement contractor.
Pete Thomson
Decommissioning Manager
Baker Hughes
Total Posts: 16
Join Date: 12/12/15

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 regards


Drilling Engineering and Planning Director
Total Posts: 12
Join Date: 13/02/12
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.
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