Fluid and Pressure Evolution in HPHT Settings of the Central Graben, North Sea

R. di Primio¹, V. Neumann¹, R. Ondrak¹, B. Horsfield¹, R. Lippmann², and R. Gaupp^2
1GFZ-Potsdam, Telegrafenberg, 14473 Potsdam, Germany
²Universität Jena, Institut für Geowissenschaften, Burgweg 11, 07749 Jena, Germany

3D petroleum system modelling offers the possibility of studying the effects and interactions of different processes on the evolution of sedimentary basins and corresponding pore fluids. However, 3D modelling is often performed only to answer specific questions, e.g. likelyhood of petroleum charge to a given prospect or the evolution of kitchen area maturity, ignoring potential interactions with additional processes. Here we present 3D modelling results from the Central Graben, North Sea, where we investigated pore pressure evolution as well as the filling history and compositional evolution of hydrocarbon phases in severly overpressured high temperature reservoirs. Of special interest was an assesment of possible interdependancies between pressure evolution scenarios and hydrocarbon phase evolution in the modelled reservoirs, as well as the identification of possible organic-inorganic interactions within the reservoir rocks.

The study area is located in the HPHT zone, centered in quadrants 30 (UK) and the Norwegian blocks 1 and 2. This zone is part of a larger province with HPHT conditions, concentrated in the deeper Mesozoic sections of the Central Graben and in the southern part of the Viking Graben. The highly overpressured Mesozoic clastic reservoirs at 4-5 km burial depths are of Triassic and Middle Jurassic age, and reach temperatures up to 194°C. The reservoirs are highly overpressured; hydrocarbons are wet gas condensates and black oils, a typical feature of many Central Graben Mesozoic reservoirs.

We compared pore presure evolution calculated assuming only differential compaction as a pressure generating mechanism, as well as using the combination of differential compaction and gas generation. The results indicate that resulting pore pressure evolution histories vary dramatically, whereby the inclusion of overpressure generated as a function of gas generation provides a better match to available fluid inclusion calibration data. Characterisation of gas generation was based on phase predictive kinetic models (PhaseKinetics of di Primio and Horsfield, 2006) for the various source rock sequences, which were augmented by definitions of secondary cracking.

Including gas generation as a pressure generation mechanism requires the definition of gas compressibility factors at variable pressures and temperatures. Gas compressibility is controlled by gas composition, which also varies as a function of source rock maturation and extent of secondary cracking. We present results on the influence of gas compressibility on pore pressure evolution, as well as the influence of variable pore pressure evolution histories on the modelled reservoir filling histories, petroleum compositional predictions and timing of organic-inorganic interactions as calibrated by petrographic analysis.

References
di Primio, R., and B. Horsfield, 2006, From petroleum type organofacies to hydrocarbon phase prediction: AAPG Bulletin, v. 90, p. 1031-1058.

 

AAPG Search and Discover Article #90066©2007 AAPG Hedberg Conference, The Hague, The Netherlands

 

AAPG Search and Discover Article #90066©2007 AAPG Hedberg Conference, The Hague, The Netherlands