HTHP Oil Well Cementing Challenges

The High Pressure/High Temperature classification applies to any well, if the bottom hole temperature is at least 150 ^oC with a pore pressure higher than 10,000 psi. These extreme values challenge the well construction process in several ways, including themes of well control, drilling equipment durability, sealing elements, drilling and completions fluids. Still, well cementing is particularly difficult due to its sensitivity to temperature, which has a tremendous effect on the reproducibility of results, making every job unique and the subject of careful engineering and laboratory testing.

Before going in detail let’s understand the basics. First, temperature accelerates the hydration process of cement hence limiting the time it remains as a maneuverable slurry in the well. For our purpose refers to its capacity to flow within a defined operational window. Chemically, a quicker hydration process can be delayed by the addition of certain materials known as retarders. However these have side effects, which vary depending on the chemical nature of the retarder, its quantity, presence of other components, and the characteristics of the cement. In summary, the higher the temperature the more noticeable these side effects will be, but this is not the limit of our consideration. Higher concentrations of cement, required in some cases to achieve higher density (high formation pore pressure), will amplify the occurrence of all the chemical reactions involved triggering even more adverse behaviours in the cement slurry,

Now let’s go back a little with some definitions. What is the objective of primary cementing? I would say the main objective is maximizing cement coverage. Therefore targets like zonal isolation and casing protection can only be achieved if cement presence is maximized in the annular gap; In other words: cement coverage. However, cement coverage is only possible if mud is completely displaced from the hole during cementing. Consequently, in HPHT one of the most detrimental chemical side effects is seen in the cement slurry rheology and its role in achieving sufficient mud displacement in a high fluid densities environment.

Now, what are the exact implications of dealing with high-density fluids? First of all, high-density fluids are required because of the high formation pore pressure to keep primary well control. This calls for high mud density, which in turn demands high-density cement slurries. In summary, the implications for the cement slurry itself and its placement are:

• Lower-than-desired pumping rates due to limited Equivalent Circulating Density or ECD. It is common in HPHT wells to have a narrow margin between fracture and pore pressure limiting the allowable displacement rates and ECD, not to exceed the fracture gradient (induced losses);
• Lower pumping rates prevent in most cases achieving proper density and rheology hierarchy, thus making more difficult mud removal;
• Lower pumping rates; also call for higher concentrations of chemicals, especially retarders, to allow longer thickening times.

Now talking about the high-density cement slurry features:

• It must be stable and pumpable at surface and at high circulating temperature;
• It must also be sufficiently retarded (to be pumpable) and be still able to set at the top of cement (at lower temperature);
• It requires a careful design conscious of changes in small temperature variations, cement batches, density variations and additive concentrations;
• It must acknowledge the limitations in laboratory testing;
• High-density cement slurries are more difficult to mix at surface and they have high solid content, which favour settling (stability issues) and/or gelling (high rheology). These chemical processes are temperature-dependent.

It must be clear at this point, that designing an adequate cement slurry system able to meet and endure the predicted requirements, by the hydraulic simulation, is fundamental. The most important of these requirements, as previously mentioned, is rheology. Here are some recommendations:

1. Surface conditions (mixability), 300 rpm reading < 300 and Yield point lower than 35 lbs/100 ft2;
2. Yield point higher than 10 lbs/100 ft2 at high temperature (conditioning in HPHT consistometer or at 185 °F);
3. If available during job planning, use HPHT rheometer to measure, at least, the mud rheology. This will be required for a more accurate hydraulic simulation. (HP/HT rheometer or viscometer is used to monitor the temperature stability of the drilling fluid, and to evaluate its rheological properties at up to 260 °C and 20,000 psi);
4. Ramp-up to ramp-down readings at each speed (300, 200, 100, 60, 30, 6, 3 rpm’s) ratios to be close to 1. Higher ratios suggest settling tendency and lower ratios could be an indication of a gelling tendency;
5. Initial consistency on the HPHT consistometer recommended to be below 30 Bc
6. Check for a consistency spike in the HPHT consistometer when the motor is shut-off (Go/No-Go Test). This is an indication of static gel strength development and it simulates what would happen during static periods, e.g., dropping wiper plugs, before circulation on top of the liner hanger;
7. Zero free fluid (if well is deviated run test at an angle);
8. Static Sedimentation test, less than 5 % deviation from theoretical density;
9. API Fluid Loss < 50 mL/30min. Use stirred fluid loss cell;
10. Run mud/spacer/cement compatibility test for rheology and thickening time (UCA as well in case of OBM). In thickening time include Go/No-Go check. If available, for liner jobs check for static gel strength of the contaminated mixture (this is important to ensure contaminated cement on top of the liner hanger can be circulated out). NOTE: cement contractor should make a recommendation for the length of the overlap;
11. Run sensitivity tests. For temperature (check for top of cement), retarder concentration (+/- 5% BWOC or 0,02 gps) and density (+/- 0,3 ppg, depending on surface mixing methodology and controls).
12. Emphasis must be to allow for sufficient thickening time (as per applicable policy) while avoiding excessive time to reach 50 psi compressive strength to minimize waiting-on-cement time.

Finally, well construction in HPHT condition implicates several challenges, with wells often deep and having narrow pressure operational window, undesirable long non-productive times and higher-than-planned costs. Proper cementing can provide tremendous benefits to keep positive well economics. Consequently, this post was intended to highlight some of the considerations that are important to well cementing in HPHT conditions. I hope you find its content helpful and if there are any questions or comments please drop them in the dedicated area below.