Rock physics and pore pressure experts | managing operations risk | Ikon Science

Operations risk

1.  High Pressure / High Temperature (HPHT)

In HPHT situations, drilling windows are typically very narrow and pore pressure prediction more problematic. When temperatures rise above 100-120°C, "traditional" pore pressure prediction is often not suitable for well planning as the porosity/effective stress approach is often complicated by mineral transformations, chemical compaction and other high temperature processes.

Ikon Science has been involved in well design in many of the HPHT wells drilled globally. We adopt a Best Practice approach underpinned by understanding and quantifying the additional pore pressure generated by these thermally-related processes. These processes can often require additional mud-weight during drilling which may in turn require additional casing strings. In addition, our fracture pressure model has been derived based on the experiences of drilling these high risk wells.

As sub-surface geology sometimes differs from predicted/expected pre-drill models during drilling, we also recommend the use of real-time monitoring on these wells to safely drill through pressure transition zones that may be unexpected or in a different depth than originally considered.








The deep-water setting in Labrador is an exciting frontier area. The well control to-date exists only on the Shelf where kick data indicate the potential for high pore pressure. In the deep-water where new seismic has been shot, this overpressure is likely also a phenomena. Studies of analogue regions such as Mid-Norway are therefore vital in terms of reducing risk in drilling future wildcat wells in this new play. The pressure regime can also control the distribution of hydrocarbons via migration and presence of seals therefore integrating an understanding from other basins will identify and high grade acreage in Labrador (Edwards et al 2015).


2. Identifying natural reservoir depletion

Depletion is typically associated with production. However, from our global experience, we also see evidence of “natural” depletion, i.e. where a connected reservoir loses pressure towards an exit point or leak point, perhaps as a result of glacial unroofing, or seal failure.

The effects are that these reservoirs have substantially lower pore pressure than their associated shales. This becomes a real drilling risk in terms of taking losses if the pre-drill model and mud-weight used assumes that the reservoir will have the same pressure as the shales.

These draining reservoirs can be most effectively modeled/predicted by use of regional geopressure studies, as these sands often exit beyond the acreage boundary of a licence block. Once identified, the mud-weights and casing string setting depths can be adjusted accordingly with the minimum of NPT.

As there is a pressure difference between the shales and reservoir, real time monitoring can be used to “see these coming” as rock properties gradually change as they are approached.  This also impacts on rock physics models by changing the impedance contrast between sand and shale such that hydrocarbon/water discrimination may not be possible.






Sands often exit beyond the acreage boundary of a licence block. Once identified through Ikon Science studies, the mud-weights can be adjusted accordingly with the minimum of NPT (Green et al 2012).