Understanding pore pressure regimes in deep water plays using global analogues
There are many different elements to a deep water play that require analogues to aid in de-risking. Analogues are often focussed 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 based on the basin-scale framework. Hydrocarbon prospectivity has been proven in deep water settings with discoveries that include areas such as Mid-Norway, Gulf of Mexico, and West Africa. A frequent problem remains, however, that deep water exploration occurs in wildcat situations, with little to no well calibration, relying solely on seismic interval velocities. Using seismic interval velocities for pressure prediction can give viable results when constrained by comparison with existing well penetrations, however, in areas where there are no previous wells either seismic interval velocities have to be trusted implicitly, which is a flawed concept in areas of diagenesis and cementation within shales, and/or global analogues must be used. 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 overall tectonostratigraphic framework is very similar on both sides of the Atlantic Margin. Other areas such as the Gulf of Mexico show analogies with Labrador in terms of water depth and sediment thickness; the nearby Grand Banks and Scotian margin contain deep water wells, and areas like the Central North Sea that are presently shallow water but contain large volumes of deep-water sediments. Constructing a pore pressure profile in deep water plays involves several stages. Firstly, the likely lithofacies in the deep-water must be understood which is achieved partly from use of seismic reflectivity data and partly from analogue with other deep-water settings. Secondly, reservoirs often have different pressures to their associated shales; they can be lower via lateral drainage or higher due to lateral transfer (centroid). If the sands are stratigraphically or structurally isolated, they will have the same pressure as the surrounding shales. Thirdly, models for shale pressure must be produced. Modelling of shale pore pressure in frontier locations is often undertaken using seismic interval velocities, often the only data type available, yet these data may not be suitable if the shales have undergone diagenesis. Lastly, pore pressure is assumed to be generated via vertical loading by sediment and undercompaction of shales; in reality, other processes such as fluid expansion and load transfer can increase the pore pressure beyond that predicted by standard techniques. These processes occur where shales, dependant on composition and age, are heated such that clay diagenesis and thermal maturation occur. This paper aims to show how the integration of global analogues can aid in a) building a pore pressure profile, b) de-risking the magnitude of the pore pressures that are predicted, and c) provide confidence in the sub-surface facies model that helps define the pore pressure model. Generation of a pressure profile requires that all elements discussed above must be considered.
AAPG Datapages/Search and Discovery Article #90325 © 2018 AAPG Europe Regional Conference, Global Analogues of the Atlantic Margin, Lisbon, Portugal, May 2-3, 2018