Well Integrity Technical Section

All,

Could anyone share the cement slurry design criteria for HPHT wells containing Co2 % H2S.

What parameters needs to considered & lab test to be conducted prior to cementing job as per API standard.

Please share any standard to comply the cement slurry design.

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Lajpat Rai
Petroleum Engineer
United Energy Pakistan Ltd
Karachi City
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Dear Lajpat

The answer to your question should be divided in two: 1- The requirement slurry performance for HPHT well and 2- what should be the cement slurry design criteria to survive in a CO2 and H2S environment.

To answer to the point 1, the principal slurry property is aligned with API standards, and is related to the Static Gel Strength Test (SGST).  The results of the test should indicate that the slurry may be achieve a 500 Lbf/100 ft2 in 45 min, from the Critical Static Gel Strength Point (CSGS Point). This test should be performed in a specific device which can simulate both slurry condition in the well: the dynamic (during pumping) and static condition (after bump the plug).  However, I have to suggest that even when API recommend 45 min for this period of time, I should say that a lower time should be considered: 20 min or lower is a good result.  My recommendation is to perform this test in a MACS2, using a profile of temperature obtained from a dynamic temperature simulation.

I don’t know if your cementing job will be done for a casing or liner, but if you have to do it for a liner, is recommendable perform the test for bottom hole and TOL condition.

The answer to the point 2, is not that easy or simple.  We must considered that the chemistry reaction responsible of the cement degradation due to CO2 attack cannot be avoided, but can (and should be) minimized considering the utilization of inert material capable to reduce the cement sheath porosity. Why? Because of the CO2 reacts principally with the water occluded in the cement matrix, producing more water as result of the chemical reaction which react with more CO2. In summary, it is an auto-catalyzed reaction. To minimize this situation with very good results, the cement blend should contain material with very small particle size and usually Fly Ash is usually considered. And what’s about H2S?  The H2S do not attack cement Portland, however there are some studies that showed a degradation of the slurry if this one contain ferrous material (or derivated from Fe like Hematite, for instance), and guess what? Normally the slurries designed for HPHT wells contain these material as a weighting agent to increase the density.

So, the recommendation is to try to use an slurry design with as lower as possible SGST (as I mentioned previously) using Fly Ash as a component in the dry cement blend, increasing the density as much as possible with alternative materials than Hematite. If you need a slurry density lower than 17.5 ppg will not be a problem, however if 18 ppg or more is required, you will have to test alternative weighting materials.

Also, a good practice is to run a test under CO2 (CO2 Test Performance), at least for 6 month if you have the time. In general, the Cementing design for CO2 environment are done with enough time to run this test and evaluate alternatives designs.

I would like to mention also, that in such well and environmental conditions, you should consider a Mechanical Tests evaluation, to verify that the Young Module and Poisson Ration of the slurry will provide a good mechanical condition and remaining capacity to survive for the life of the well, keeping the zonal isolation integrity.

Please, feel free to contact me if any additional query arise.

Marcelo Venturino

Well Cementing Consulting

Technical Director

www.wellcementingconsulting.com

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Marcelo Venturino
Cementing & Fluid Specialist
Well Cementing Consulting
www.wellcementingconsulting.com

Dear Lajpat,

Marcelo's suggestions are very good and to the point. Here's my 2 cents:

I wouldn't worry about CO2 and cement. Cement's high pH is one of the reasons you use it: it protects steel agains acid corrosion - and CO2 is by far the most common causes of it in O&G. Years of research have shown that you need a lot of CO2 and water to carbonate and then leach cement, and for that you need a substantial leakage pathway to start with. In an HPHT well that creates a much clearer and more present danger than eventual cement degradation. Fly ash "decreases" degradation by CO2, but mostly by shifting your C/S ratio, eliminating your portlandite crystals and changing the C-S-H gel structure instead of simple pore plugging. The snag is that portlandite-free cement has a lower equilibrium pH (say, around 10 instead of around 12) so lower corrosion protection. C-S-H carbonation is slower than portlandite, but so is its ability to buffer the cement pore water. On the other hand it is quite possible that class G cement is effectively passivated by exposure to CO2, so I wouldn't focus on lab degradation tests since they are not representative at all of downhole conditions and long-term behavior.

So I would think about placing a competent cement sheath, and using undiluted cement. Marcelo gave recommendations for avoiding gas migration during setting (chimneys). If you'd like a proper design instead of rules of thumb, I have a gas migration simulator. You should also think about avoiding microannuli, since HPHT means large stresses related to pressure and temperature swings. Hence Marcelo's suggestion to understand the roles of Young's Modulus and Poisson's ratio - although you'd need a mechanical model to appreciate that fully.

More generally there are two sides to HPHT: high pressure becomes an issue when you need a very heavy slurry and must use hematite. This gives you a headache when designing a stable slurry, testing it and mixing it in the field. Besides the fact that hematite and H2S don't mix well, as Marcelo said. HT is a bigger deal: aside from strength retrogression above 110degC (do worry about it, please!), most off-the-shelf retarder and fluid loss control agents stop working roughly around 150degC. So you need to use inorganic additives that tend to be proprietary to large cementing companies.

Hope it helps,

Matteo

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Matteo Loizzo
Well integrity consultant
Berlin

Can I add that your recipe for an HTHP slurry will be easy to design and lab test so it is appropriate.  More importantly is to get the slurry in place so there is a total bond around the casing that prevents H2S and CO2 gases from migrating up the annulus and later accelerating corrosion of your casing.  If there are gas zones in the formation being cased it is imperative that hole quality be a drift gauge for the casing and centralizers and that the casing be rotated during cementation.   Otherwise expect a low quality bond and corrosion troubles later.  Good discussion at  http://www.slb.com/~/media/Files/resources/oilfield_review/ors94/0494/composite.pdf

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Wayne Needoba
D&C, Decommission Project Coordinator
LIS Thailand Co. Ltd.
KarawaraWA