There are many different elements to a play that require analogues to aid in de-risking, especially in areas with limited offset well data. Analogues are often focused on a similar basin-scale tectonostratigraphic framework, but there are many aspects to a geological-pressure model that must be de-risked, for example, sand-shale geometries, reservoir plumbing, TOC within shales, thermal evolution, and sedimentation rate. There are many examples of analogous processes and relationships that can de-risk the pore pressure from settings that wouldn’t be considered
analogous if solely based on the basin-scale framework.
This paper aims to discuss the considerations that must be made when building a geological-pressure model and to show how the integration of global analogues can help in de-risking the magnitude of the pore pressures that are predicted, and provide confidence in the sub-surface facies distributions that help define the pore pressure model. There are several examples of analogous pairs of basins where one is more heavily drilled and thus provides a rich database, and the other has minimal to-no wells, yet shows significant potential for exploration. One such pair would be the deep-water areas of Mid-Norway (data-rich) and Labrador (data-poor), where the tectonostratigraphic framework is very similar on both sides of the Atlantic Margin. Other examples from French Guiana, Guyana, and Suriname include the Zaedyus, Jaguar, and Liza discoveries based on experience in West Africa.
One of the most important realizations when building a geological-pressure model is that the evolution of the in-situ pore pressure is a function of the processes a rock experiences, which can be independent of the absolute geological age, i.e., pressure is primarily controlled by vertical loading, thermal and chemical diagenesis, and the structural framework. For example, lessons from Cretaceous-aged rocks in one basin might be the appropriate analogue for a Tertiary-aged rock in another basin.
